Generic Environmental 

Impact Statement for License 

Renewal of Nuclear Plants

Supplement 54 

Regarding Byron Station, 

Units 1 and 2 

Draft Report for Comment

Office of Nuclear Reactor Regulation

NUREG-1437

Supplement 54 
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Generic Environmental

Impact Statement for License 

Renewal of Nuclear Plants

Supplement 54 

Regarding Byron Station, 

Units 1 and 2

Draft Report for Comment

Manuscript Completed: December 2014

Date Published: December 2014

Office of Nuclear Reactor Regulation

NUREG-1437

Supplement 54

iii

1 COVER SHEET

2 Responsible Agency: U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor 

3 Regulation. There are no cooperating agencies involved in the preparation of this document.

4 Title: Generic Environmental Impact Statement for License Renewal of Nuclear Plants, 

5 Supplement 54, Regarding Byron Station, Units 1 and 2, Draft Report for Comment 

6 (NUREG-1437). Byron Station, Units 1 and 2 (Byron), is located in Ogle County, Illinois.

7 For additional information or copies of this document contact:

8 Division of License Renewal

9 U.S. Nuclear Regulatory Commission

10 Office of Nuclear Reactor Regulation

11 Mail Stop O-11F1

12 11555 Rockville Pike

13 Rockville, Maryland 20852

14 Phone: 1-800-368-5642, extension 3306

15 Fax: (301) 415-2002

16 Email: lois.james@nrc.gov

17 ABSTRACT

18 This supplemental environmental impact statement (SEIS) has been prepared in response to an 

19 application submitted by Exelon Generation Company, LLC (Exelon), to renew the operating 

20 license for Byron Station, Units 1 and 2 (Byron), for an additional 20 years.

21 This SEIS includes the preliminary analysis that evaluates the environmental impacts of the 

22 proposed action and alternatives to the proposed action. Alternatives considered include: new 

23 nuclear generation, coal-integrated gasification combined cycle (IGCC), natural gas 

24 combined-cycle (NGCC), combination (NGCC, wind, and solar generation), replacement power, 

25 and no renewal of the license (the no-action alternative).

26 The U.S. Nuclear Regulatory Commission (NRC) staff’s preliminary recommendation is that the 

27 adverse environmental impacts of license renewal for Byron are not so great that preserving the 

28 option of license renewal for energy-planning decisionmakers would be unreasonable. This 

29 recommendation is based on the following:

30  the analysis and findings in NUREG–1437, Volumes 1 and 2, Generic 

31 Environmental Impact Statement for License Renewal of Nuclear Plants; 

32  the Environmental Report submitted by Exelon;

33  consultation with Federal, state, local, and tribal government agencies;

34  the NRC’s environmental review; and

35  consideration of public comments received during the scoping process.

v 

1 TABLE OF CONTENTS

2 ABSTRACT.............................................................................................................................. iii

3 TABLE OF CONTENTS ............................................................................................................ v

4 FIGURES................................................................................................................................. xv

5 TABLES ................................................................................................................................ xvii

6 EXECUTIVE SUMMARY ........................................................................................................ xxi

7 ABBREVIATIONS AND ACRONYMS ................................................................................. xxvii

8 1.0 INTRODUCTION .......................................................................................................... 1-1

9 1.1 Proposed Federal Action..................................................................................... 1-1

10 1.2 Purpose and Need for Proposed Federal Action ................................................. 1-1

11 1.3 Major Environmental Review Milestones............................................................. 1-1

12 1.4 Generic Environmental Impact Statement........................................................... 1-3

13 1.5 Supplemental Environmental Impact Statement.................................................. 1-5

14 1.6 Decisions to be Supported by the SEIS .............................................................. 1-6

15 1.7 Cooperating Agencies......................................................................................... 1-6

16 1.8 Consultations ...................................................................................................... 1-6

17 1.9 Correspondence ................................................................................................. 1-7

18 1.10 Status of Compliance.......................................................................................... 1-7

19 1.11 Related State and Federal Activities ................................................................... 1-7

20 1.12 References ......................................................................................................... 1-8

21 2.0 ALTERNATIVES INCLUDING THE PROPOSED ACTION .......................................... 2-1

22 2.1 Proposed Action ................................................................................................. 2-1

23 2.1.1 Plant Operations During the License Renewal Term .............................. 2-1

24 2.1.2 Refurbishment and Other Activities Associated With License Renewal .. 2-2

25 2.1.3 Termination of Nuclear Power Plant Operations and Decommissioning 

26 After the License Renewal Term ............................................................ 2-3

27 2.2 Alternatives......................................................................................................... 2-3

28 2.2.1 No-Action Alternative.............................................................................. 2-3

29 2.2.2 Replacement Power Alternatives............................................................ 2-4

30 2.2.2.1 New Nuclear Alternative ...................................................... 2-11

31 2.2.2.2 IGCC Alternative.................................................................. 2-12

32 2.2.2.3 NGCC Alternative ................................................................ 2-14

33 2.2.2.4 Combination Alternative (NGCC, Wind, Solar)..................... 2-15

34 2.2.2.5 Purchased Power Alternative............................................... 2-18

35 2.3 Alternatives Considered but Dismissed............................................................. 2-18

36 2.3.1 Energy Conservation and Energy Efficiency......................................... 2-18

37 2.3.2 Solar .................................................................................................... 2-19
Table of Contents

vi

1 2.3.3 Wind..................................................................................................... 2-19

2 2.3.3.1 Offshore Wind...................................................................... 2-20

3 2.3.3.2 Wind Power with Storage..................................................... 2-20

4 2.3.3.3 Conclusion........................................................................... 2-21

5 2.3.4 Biomass ............................................................................................... 2-21

6 2.3.5 Hydroelectric ........................................................................................ 2-22

7 2.3.6 Wave and Ocean Energy ..................................................................... 2-22

8 2.3.7 Fuel Cells ............................................................................................. 2-22

9 2.3.8 Delayed Retirement.............................................................................. 2-23

10 2.3.9 Geothermal .......................................................................................... 2-23

11 2.3.10 Municipal Solid Waste.......................................................................... 2-24

12 2.3.11 Petroleum............................................................................................. 2-24

13 2.3.12 SCPC................................................................................................... 2-25

14 2.4 Comparison of Alternatives ............................................................................... 2-25

15 2.5 References ....................................................................................................... 2-28

16 3.0 AFFECTED ENVIRONMENT........................................................................................ 3-1

17 3.1 Description of Nuclear Power Plant Facility and Operation ................................. 3-1

18 3.1.1 External Appearance and Setting........................................................... 3-1

19 3.1.2 Nuclear Reactor Systems....................................................................... 3-5

20 3.1.3 Cooling and Auxiliary Water Systems..................................................... 3-5

21 3.1.3.1 Circulating Water System....................................................... 3-6

22 3.1.3.2 Nonessential Service Water System ...................................... 3-8

23 3.1.3.3 Essential Service Water System ............................................ 3-8

24 3.1.3.4 Cooling and Auxiliary Water Treatment.................................. 3-9

25 3.1.4 Radioactive Waste Management Systems ............................................. 3-9

26 3.1.4.1 Radioactive Liquid Waste Management............................... 3-10

27 3.1.4.2 Radioactive Gaseous Waste Management .......................... 3-11

28 3.1.4.3 Radioactive Solid Waste Management................................. 3-13

29 3.1.4.4 Radioactive Waste Storage.................................................. 3-13

30 3.1.4.5 Radiological Environmental Monitoring Program.................. 3-13

31 3.1.5 Nonradioactive Waste Management Systems ...................................... 3-14

32 3.1.6 Utility and Transportation Infrastructure................................................ 3-15

33 3.1.6.1 Electricity ............................................................................. 3-15

34 3.1.6.2 Fuel ..................................................................................... 3-15

35 3.1.6.3 Water................................................................................... 3-15

36 3.1.6.4 Transportation Systems ....................................................... 3-15

37 3.1.6.5 Power Transmission Systems.............................................. 3-15

38 3.1.7 Nuclear Power Plant Operations and Maintenance .............................. 3-16

39 3.2 Land Use and Visual Resources....................................................................... 3-16

40 3.2.1 Land Use.............................................................................................. 3-16

41 3.2.2 Visual Resources ................................................................................. 3-18
Table of Contents

vii

1 3.3 Meteorology, Air Quality, and Noise.................................................................. 3-18

2 3.3.1 Meteorology and Climatology ............................................................... 3-18

3 3.3.2 Air Quality ............................................................................................ 3-20

4 3.3.3 Noise.................................................................................................... 3-22

5 3.4 Geologic Environment....................................................................................... 3-23

6 3.4.1 Physiography and Geology .................................................................. 3-23

7 3.4.2 Soils ..................................................................................................... 3-24

8 3.4.3 Seismic Setting .................................................................................... 3-25

9 3.5 Water Resources .............................................................................................. 3-25

10 3.5.1 Surface Water Resources .................................................................... 3-25

11 3.5.1.1 Surface Water Hydrology..................................................... 3-25

12 3.5.1.2 Surface Water Use............................................................... 3-28

13 3.5.1.3 Surface Water Quality and Effluents .................................... 3-29

14 3.5.2 Groundwater Resources ...................................................................... 3-32

15 3.5.2.1 Site Description and Hydrogeology...................................... 3-32

16 3.5.2.2 Groundwater Use................................................................. 3-36

17 3.5.2.3 Groundwater Quality............................................................ 3-36

18 3.6 Terrestrial Resources........................................................................................ 3-37

19 3.6.1 Byron Ecoregion................................................................................... 3-37

20 3.6.2 Byron Site and Vicinity ......................................................................... 3-38

21 3.6.2.1 Summary of Past Byron Surveys and Reports ..................... 3-38

22 3.6.2.2 Vegetation ........................................................................... 3-39

23 3.6.2.3 Wildlife................................................................................. 3-42

24 3.6.3 Transmission Line Corridors................................................................. 3-46

25 3.6.4 WHC Wildlife at Work Program ............................................................ 3-46

26 3.7 Aquatic Resources............................................................................................ 3-47

27 3.8 Special Status Species and Habitats................................................................. 3-59

28 3.8.1 Species and Habitats Protected Under the Endangered Species Act ... 3-59

29 3.8.1.1 Action Area .......................................................................... 3-59

30 3.8.1.2 Species and Habitats under the FWS’s Jurisdiction ............. 3-60

31 3.8.1.3 Species and Habitats Under NMFS’s Jurisdiction ................ 3-64

32 3.8.2 Species and Habitats Protected Under the Magnuson–Stevens Act..... 3-65

33 3.9 Historic and Cultural Resources........................................................................ 3-65

34 3.9.1 Cultural Background............................................................................. 3-65

35 3.9.2 Historic and Cultural Resources ........................................................... 3-67

36 3.10 Socioeconomics................................................................................................ 3-68

37 3.10.1 Power Plant Employment and Expenditures......................................... 3-68

38 3.10.2 Regional Economic Characteristics ...................................................... 3-69

39 3.10.2.1 Employment and Income ..................................................... 3-69

40 3.10.2.2 Unemployment..................................................................... 3-72
Table of Contents

viii

1 3.10.3 Demographic Characteristics ............................................................... 3-72

2 3.10.3.1 Transient Population............................................................ 3-74

3 3.10.3.2 Migrant Farm Workers ......................................................... 3-76

4 3.10.4 Housing and Community Services........................................................ 3-78

5 3.10.4.1 Housing ............................................................................... 3-78

6 3.10.4.2 Education............................................................................. 3-79

7 3.10.4.3 Public Water Supply............................................................. 3-79

8 3.10.5 Tax Revenues...................................................................................... 3-80

9 3.10.6 Local Transportation............................................................................. 3-84

10 3.11 Human Health................................................................................................... 3-85

11 3.11.1 Radiological Exposure and Risk........................................................... 3-85

12 3.11.2 Chemical Hazards................................................................................ 3-87

13 3.11.3 Microbiological Hazards ....................................................................... 3-87

14 3.11.4 Electromagnetic Fields ......................................................................... 3-89

15 3.11.5 Other Hazards...................................................................................... 3-90

16 3.12 Environmental Justice....................................................................................... 3-90

17 3.12.1 Minority Population............................................................................... 3-91

18 3.12.2 Low-Income Population........................................................................ 3-93

19 3.13 Waste Management and Pollution Prevention................................................... 3-95

20 3.13.1 Radioactive Waste ............................................................................... 3-95

21 3.13.2 Nonradioactive Waste .......................................................................... 3-95

22 3.14 References ....................................................................................................... 3-95

23 4.0 ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS......................... 4-1

24 4.1 Introduction......................................................................................................... 4-1

25 4.2 Land Use and Visual Resources......................................................................... 4-1

26 4.2.1 Proposed Action..................................................................................... 4-1

27 4.2.2 No-Action Alternative.............................................................................. 4-2

28 4.2.2.1 Land Use ............................................................................... 4-2

29 4.2.2.2 Visual Resources................................................................... 4-2

30 4.2.3 New Nuclear Alternative......................................................................... 4-2

31 4.2.3.1 Land Use .............................................................................. 4-2

32 4.2.3.2 Visual Resources................................................................... 4-3

33 4.2.4 Integrated Gasification Combined Cycle (IGCC) Alternative................... 4-3

34 4.2.4.1 Land Use ............................................................................... 4-3

35 4.2.4.2 Visual Resources................................................................... 4-3

36 4.2.5 Natural Gas Combined-Cycle (NGCC) Alternative ................................. 4-3

37 4.2.5.1 Land Use ............................................................................... 4-3

38 4.2.5.2 Visual Resources................................................................... 4-4

39 4.2.6 Combination Alternative (NGCC, Wind, Solar) ....................................... 4-4

40 4.2.6.1 Land Use ............................................................................... 4-4

41 4.2.6.2 Visual Resources................................................................... 4-4
Table of Contents

ix

1 4.2.7 Purchased Power................................................................................... 4-5

2 4.2.7.1 Land Use ............................................................................... 4-5

3 4.2.7.2 Visual Resources................................................................... 4-5

4 4.3 Air Quality and Noise .......................................................................................... 4-5

5 4.3.1 Proposed Action..................................................................................... 4-5

6 4.3.1.1 Air Quality .............................................................................. 4-5

7 4.3.1.2 Noise ..................................................................................... 4-6

8 4.3.2 No-Action Alternative.............................................................................. 4-6

9 4.3.2.1 Air Quality .............................................................................. 4-6

10 4.3.2.2 Noise ..................................................................................... 4-6

11 4.3.3 New Nuclear Alternative......................................................................... 4-7

12 4.3.3.1 Air Quality .............................................................................. 4-7

13 4.3.3.2 Noise ..................................................................................... 4-8

14 4.3.4 IGCC Alternative .................................................................................... 4-9

15 4.3.4.1 Air Quality .............................................................................. 4-9

16 4.3.4.2 Noise ................................................................................... 4-12

17 4.3.5 NGCC Alternative................................................................................. 4-13

18 4.3.5.1 Air Quality ............................................................................ 4-13

19 4.3.5.2 Noise ................................................................................... 4-15

20 4.3.6 Combination Alternative (NGCC, Wind, Solar) ..................................... 4-15

21 4.3.6.1 Air Quality ............................................................................ 4-16

22 4.3.6.2 Noise ................................................................................... 4-17

23 4.3.7 Purchased Power................................................................................. 4-19

24 4.3.7.1 Air Quality ............................................................................ 4-19

25 4.3.7.2 Noise ................................................................................... 4-19

26 4.3.8 Conclusions ......................................................................................... 4-19

27 4.4 Geologic Environment....................................................................................... 4-20

28 4.4.1 Proposed Action................................................................................... 4-21

29 4.4.2 No-Action Alternative............................................................................ 4-21

30 4.4.3 New Nuclear Alternative....................................................................... 4-21

31 4.4.4 IGCC Alternative .................................................................................. 4-22

32 4.4.5 NGCC Alternative................................................................................. 4-22

33 4.4.6 Combination Alternative (NGCC, Wind, Solar) ..................................... 4-22

34 4.4.7 Purchased Power................................................................................. 4-22

35 4.5 Water Resources .............................................................................................. 4-22

36 4.5.1 Proposed Action................................................................................... 4-22

37 4.5.1.1 Surface Water Resources.................................................... 4-22

38 4.5.1.2 Groundwater Resources ...................................................... 4-24

39 4.5.2 No-Action Alternative............................................................................ 4-26

40 4.5.2.1 Surface Water Resources.................................................... 4-26

41 4.5.2.2 Groundwater Resources ...................................................... 4-26
Table of Contents

x 

1 4.5.3 New Nuclear Alternative....................................................................... 4-26

2 4.5.3.1 Surface Water Resources.................................................... 4-26

3 4.5.3.2 Groundwater Resources ...................................................... 4-27

4 4.5.4 IGCC Alternative .................................................................................. 4-27

5 4.5.4.1 Surface Water Resources.................................................... 4-27

6 4.5.4.2 Groundwater Resources ...................................................... 4-28

7 4.5.5 NGCC Alternative................................................................................. 4-28

8 4.5.5.1 Surface Water Resources.................................................... 4-28

9 4.5.5.2 Groundwater Resources ...................................................... 4-29

10 4.5.6 Combination Alternative (NGCC, Wind, Solar) ..................................... 4-29

11 4.5.6.1 Surface Water Resources.................................................... 4-29

12 4.5.6.2 Groundwater Resources ...................................................... 4-30

13 4.5.7 Purchased Power................................................................................. 4-30

14 4.5.7.1 Surface Water Resources.................................................... 4-30

15 4.5.7.2 Groundwater Resources ...................................................... 4-30

16 4.6 Terrestrial Resources........................................................................................ 4-30

17 4.6.1 Proposed Action................................................................................... 4-30

18 4.6.1.1 Generic Terrestrial Resource Issues.................................... 4-31

19 4.6.1.2 Effects on Terrestrial Resources (Noncooling System 

20 Impacts)............................................................................... 4-31

21 4.6.1.3 Water Use Conflicts with Terrestrial Resources (Plants 

22 with Cooling Ponds or Cooling Towers Using Makeup 

23 Water from a River).............................................................. 4-32

24 4.6.2 No-Action Alternative............................................................................ 4-33

25 4.6.3 New Nuclear Alternative....................................................................... 4-33

26 4.6.4 IGCC Alternative .................................................................................. 4-34

27 4.6.5 NGCC Alternative................................................................................. 4-35

28 4.6.6 Combination Alternative (NGCC, Wind, Solar) ..................................... 4-35

29 4.6.7 Purchased Power................................................................................. 4-36

30 4.7 Aquatic Resources............................................................................................ 4-36

31 4.7.1 Proposed Action................................................................................... 4-37

32 4.7.1.1 Generic GEIS Issues ........................................................... 4-37

33 4.7.1.2 Water Use Conflicts With Aquatic Resources....................... 4-38

34 4.7.2 No-Action Alternative............................................................................ 4-38

35 4.7.3 New Nuclear Alternative....................................................................... 4-38

36 4.7.4 IGCC Alternative .................................................................................. 4-39

37 4.7.5 NGCC Alternative................................................................................. 4-40

38 4.7.6 Combination Alternative (NGCC, Wind, Solar) ..................................... 4-40

39 4.7.7 Purchased Power................................................................................. 4-40
Table of Contents

xi

1 4.8 Special Status Species and Habitats................................................................. 4-41

2 4.8.1 Proposed Action................................................................................... 4-41

3 4.8.1.1 Species and Habitats Protected Under the Endangered 

4 Species Act.......................................................................... 4-41

5 4.8.1.2 Species and Habitats Protected Under the Magnuson–

6 Stevens Act ......................................................................... 4-43

7 4.8.2 No-Action Alternative............................................................................ 4-43

8 4.8.3 New Nuclear Alternative....................................................................... 4-43

9 4.8.4 IGCC Alternative .................................................................................. 4-44

10 4.8.5 NGCC Alternative................................................................................. 4-44

11 4.8.6 Combination Alternative (NGCC, Wind, Solar) ..................................... 4-45

12 4.8.7 Purchased Power................................................................................. 4-45

13 4.9 Historic and Cultural Resources........................................................................ 4-45

14 4.9.1 Proposed Action................................................................................... 4-45

15 4.9.2 No-Action Alternative............................................................................ 4-48

16 4.9.3 New Nuclear Alternative....................................................................... 4-48

17 4.9.4 IGCC Alternative .................................................................................. 4-48

18 4.9.5 NGCC Alternative................................................................................. 4-49

19 4.9.6 Combination Alternative (NGCC, Wind, Solar) ..................................... 4-49

20 4.9.7 Purchased Power................................................................................. 4-50

21 4.10 Socioeconomics................................................................................................ 4-50

22 4.10.1 Proposed Action................................................................................... 4-50

23 4.10.2 No-Action Alternative............................................................................ 4-51

24 4.10.2.1 Socioeconomics................................................................... 4-51

25 4.10.2.2 Transportation...................................................................... 4-52

26 4.10.3 New Nuclear Alternative....................................................................... 4-52

27 4.10.3.1 Socioeconomics................................................................... 4-52

28 4.10.3.2 Transportation...................................................................... 4-53

29 4.10.4 IGCC Alternative .................................................................................. 4-53

30 4.10.4.1 Socioeconomics................................................................... 4-53

31 4.10.4.2 Transportation...................................................................... 4-54

32 4.10.5 NGCC Alternative................................................................................. 4-55

33 4.10.5.1 Socioeconomics................................................................... 4-55

34 4.10.5.2 Transportation...................................................................... 4-55

35 4.10.6 Combination Alternative (NGCC, Wind, Solar) ..................................... 4-56

36 4.10.6.1 Socioeconomics................................................................... 4-56

37 4.10.6.2 Transportation...................................................................... 4-57

38 4.10.7 Purchased Power................................................................................. 4-57

39 4.10.7.1 Socioeconomics................................................................... 4-57

40 4.10.7.2 Transportation...................................................................... 4-57
Table of Contents

xii

1 4.11 Human Health................................................................................................... 4-58

2 4.11.1 Proposed Action................................................................................... 4-58

3 4.11.1.1 Normal Operating Conditions............................................... 4-58

4 4.11.1.2 Environmental Impacts of Postulated Accidents................... 4-62

5 4.11.2 No-Action Alternative............................................................................ 4-68

6 4.11.3 New Nuclear Alternative....................................................................... 4-69

7 4.11.4 IGCC Alternative .................................................................................. 4-69

8 4.11.5 NGCC Alternative................................................................................. 4-70

9 4.11.6 Combination Alternative (NGCC, Wind, Solar) ..................................... 4-70

10 4.11.7 Purchased Power................................................................................. 4-70

11 4.12 Environmental Justice....................................................................................... 4-71

12 4.12.1 Proposed Action................................................................................... 4-71

13 4.12.2 No-Action Alternative............................................................................ 4-73

14 4.12.3 New Nuclear Alternative....................................................................... 4-73

15 4.12.4 IGCC Alternative .................................................................................. 4-74

16 4.12.5 NGCC Alternative................................................................................. 4-74

17 4.12.6 Combination Alternative (NGCC, Wind, Solar) ..................................... 4-75

18 4.12.7 Purchased Power................................................................................. 4-75

19 4.13 Waste Management and Pollution Prevention................................................... 4-75

20 4.13.1 Proposed Action................................................................................... 4-75

21 4.13.1.1 10 CFR 51.23 (Continued Storage Rule) and 

22 10 CFR 51, Subpart A, Table B-1 (License Renewal) .......... 4-76

23 4.13.1.2 CLI-14-08: Holding that Revised 10 CFR 51.23 and 

24 NUREG-2157 Satisfy NRC’s NEPA Obligations for 

25 Continued Storage and Directing Staff to Account for 

26 Environmental Impacts In NUREG-2157.............................. 4-79

27 4.13.1.3 At-Reactor Storage .............................................................. 4-79

28 4.13.1.4 Away-From-Reactor Storage ............................................... 4-80

29 4.13.1.5 Cumulative Impacts ............................................................. 4-82

30 4.13.1.6 Conclusion........................................................................... 4-82

31 4.13.2 No-Action Alternative............................................................................ 4-82

32 4.13.3 New Nuclear Alternative....................................................................... 4-83

33 4.13.4 IGCC Alternative .................................................................................. 4-83

34 4.13.5 NGCC Alternative................................................................................. 4-83

35 4.13.6 Combination Alternative (NGCC, Wind, Solar) ..................................... 4-84

36 4.13.7 Purchased Power................................................................................. 4-84

37 4.14 Evaluation of New and Potentially Significant Information................................. 4-84

38 4.15 Impacts Common to All Alternatives.................................................................. 4-85

39 4.15.1 Fuel Cycle ............................................................................................ 4-85

40 4.15.1.1 Uranium Fuel Cycle ............................................................. 4-85

41 4.15.1.2 Replacement Power Plant Fuel Cycles ................................ 4-86
Table of Contents

xiii

1 4.15.2 Terminating Power Plant Operations and Decommissioning ................ 4-87

2 4.15.2.1 Existing Nuclear Power Plant............................................... 4-87

3 4.15.2.2 Replacement Power Plants.................................................. 4-88

4 4.15.3 Greenhouse Gas Emissions and Climate Change................................ 4-89

5 4.15.3.1 Greenhouse Gas Emissions From the Proposed Project 

6 and Alternatives ................................................................... 4-89

7 4.15.3.2 Climate Change Impacts to Resource Areas ....................... 4-92

8 4.16 Cumulative Impacts of the Proposed Action...................................................... 4-97

9 4.16.1 Air Quality and Noise............................................................................ 4-98

10 4.16.1.1 Air Quality ............................................................................ 4-98

11 4.16.1.2 Noise ................................................................................... 4-99

12 4.16.1.3 Conclusion......................................................................... 4-100

13 4.16.2 Geology and Soils .............................................................................. 4-100

14 4.16.3 Water Resources ............................................................................... 4-100

15 4.16.3.1 Surface Water Resources.................................................. 4-100

16 4.16.3.2 Groundwater Resources .................................................... 4-102

17 4.16.3.3 Conclusion......................................................................... 4-102

18 4.16.4 Terrestrial Resource........................................................................... 4-102

19 4.16.4.1 Historic Conditions............................................................. 4-103

20 4.16.4.2 Urbanization ...................................................................... 4-103

21 4.16.4.3 Agricultural Runoff ............................................................. 4-103

22 4.16.4.4 Park and Conservation Areas ............................................ 4-103

23 4.16.4.5 Unit 2 Steam Generator Replacement ............................... 4-104

24 4.16.4.6 Conclusion......................................................................... 4-104

25 4.16.5 Aquatic Resources ............................................................................. 4-104

26 4.16.5.1 Past River Development, Channelization, and Damming ... 4-105

27 4.16.5.2 Energy Development ......................................................... 4-105

28 4.16.5.3 Runoff from Agriculture and Municipal Facilities................. 4-106

29 4.16.5.4 Parks and Recreational Areas ........................................... 4-106

30 4.16.5.5 Conclusion......................................................................... 4-106

31 4.16.6 Historic and Cultural Resources ......................................................... 4-106

32 4.16.7 Socioeconomics ................................................................................. 4-107

33 4.16.7.1 Unit 2 Steam Generator Replacement ............................... 4-107

34 4.16.7.2 Units 1 and 2 Reactor Pressure Vessel Head 

35 Replacement...................................................................... 4-108

36 4.16.7.3 Conclusion......................................................................... 4-108

37 4.16.8 Human Health .................................................................................... 4-108

38 4.16.9 Environmental Justice ........................................................................ 4-109

39 4.16.9.1 Unit 2 Steam Generator Replacement ............................... 4-110

40 4.16.9.2 Units 1 and 2 Reactor Pressure Vessel Head 

41 Replacement...................................................................... 4-110

42 4.16.9.3 Conclusion......................................................................... 4-110
Table of Contents

xiv

1 4.16.10 Waste Management and Pollution Prevention.................................... 4-110

2 4.16.11 Global Climate Change ...................................................................... 4-111

3 4.16.12 Summary of Cumulative Impacts........................................................ 4-113

4 4.17 Resource Commitments Associated With the Proposed Action....................... 4-115

5 4.17.1 Unavoidable Adverse Environmental Impacts .................................... 4-115

6 4.17.2 Relationship Between Short-Term Use of the Environment and 

7 Long-Term Productivity ...................................................................... 4-116

8 4.17.3 Irreversible and Irretrievable Commitment of Resources .................... 4-117

9 4.18 References ..................................................................................................... 4-117

10 5.0 CONCLUSION.............................................................................................................. 5-1

11 5.1 Environmental Impacts of License Renewal........................................................ 5-1

12 5.2 Comparison of Alternatives ................................................................................. 5-1

13 5.3 Recommendations.............................................................................................. 5-2

14 6.0 LIST OF PREPARERS ................................................................................................. 6-1

15 7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS TO WHOM COPIES 

16 OF THIS SEIS ARE SENT ............................................................................................ 7-1

17 8.0 INDEX........................................................................................................................... 8-1

18 APPENDIX A. COMMENTS RECEIVED ON THE BYRON STATION 

19 ENVIRONMENTAL REVIEW........................................................................ A-1

20 APPENDIX B. APPLICABLE LAWS, REGULATIONS, AND OTHER 

21 REQUIREMENTS......................................................................................... B-1

22 APPENDIX C. CONSULTATION CORRESPONDENCE ..................................................... C-1

23 APPENDIX D. CHRONOLOGY OF ENVIRONMENTAL REVIEW 

24 CORRESPONDENCE .................................................................................. D-1

25 APPENDIX E. PROJECTS CONSIDERED IN THE CUMULATIVE IMPACTS 

26 ANALYSIS.................................................................................................... E-1

27 APPENDIX F. U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION 

28 OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR BYRON 

29 STATION, UNITS 1 AND 2, IN SUPPORT OF LICENSE RENEWAL 

30 APPLICATION REVIEW............................................................................... F-1
xv 

1 FIGURES

2 Figure 1–1. Environmental Review Process........................................................................ 1-2

3 Figure 1–2. Environmental Issues Evaluated for License Renewal ..................................... 1-5

4 Figure 2–1. Territories of MISO and PJM Interconnection................................................... 2-6

5 Figure 3–1. Byron 50-Mile Radius Map............................................................................... 3-2

6 Figure 3–2. Byron 6-Mile Radius Map................................................................................. 3-3

7 Figure 3–3. Byron Site Boundary ........................................................................................ 3-4

8 Figure 3–4. Closed-Cycle Cooling System with Natural Draft Cooling Tower...................... 3-6

9 Figure 3–5. Byron Cooling Water Intake and Discharge Pipelines ...................................... 3-7

10 Figure 3–6. Site Topography ............................................................................................ 3-24

11 Figure 3–7. Rock River Basin in Illinois and Wisconsin..................................................... 3-26

12 Figure 3–8. The Rock River and USGS Stream Gaging Stations in the Vicinity of 

13 Byron ............................................................................................................. 3-27

14 Figure 3–9. NPDES Discharge Locations ......................................................................... 3-31

15 Figure 3–10. Generalized Hydrogeologic Column of Byron................................................. 3-33

16 Figure 3–11. Generalized East – West Hydrogeologic Cross Section................................. 3-35

17 Figure 3–12. Rock River Aquatic Survey Sampling Locations............................................. 3-49

18 Figure 3–13. Minority Block Groups Within a 50-mi Radius of Byron .................................. 3-92

19 Figure 3–14. Low-Income Block Groups Within a 50-mi (80-km) Radius of Byron .............. 3-94

xvii

1 TABLES

2 Table ES–1. Summary of NRC Conclusions Relating to Site-Specific Impacts of 

3 License Renewal............................................................................................. xxiii

4 Table 2–1. Summary of Replacement Power Alternatives and Key Characteristics 

5 Considered in Depth ........................................................................................ 2-9

6 Table 2–2. Summary of Environmental Impacts of Proposed Action and 

7 Alternatives.................................................................................................... 2-26

8 Table 3–1. Air Emission Estimates for Permitted Combustion Sources at Byron ............. 3-21

9 Table 3–2. Common Noise Sources and Noise Levels .................................................... 3-22

10 Table 3–3. Annual Surface Water Withdrawals and Return Discharges to the Rock 

11 River, Byron................................................................................................... 3-28

12 Table 3–4. National Pollutant Discharge Elimination System-Permitted Outfalls, 

13 Byron ............................................................................................................. 3-30

14 Table 3–5. State-Listed Plant Species in Ogle County..................................................... 3-41

15 Table 3–6. Most Common or Abundant Wildlife on the Byron Site................................... 3-43

16 Table 3–7. State-Listed Bird Species in Ogle County ...................................................... 3-44

17 Table 3–8. State-Listed Mammal Species in Illinois ......................................................... 3-45

18 Table 3–9. State-Listed Reptile and Amphibian Species in Ogle County ......................... 3-46

19 Table 3–10. Sampling Locations for Preoperational and Operational Aquatic 

20 Monitoring and Surveys of the Rock River ..................................................... 3-48

21 Table 3–11. Fish Species Collected in the Vicinity of Byron During EAI Baseline 

22 Monitoring, 1973–1974 .................................................................................. 3-54

23 Table 3–12. Fish Species Collected Downstream of Byron During INHS Study, 

24 1986–1987..................................................................................................... 3-56

25 Table 3–13. Fish Species Collected in the Vicinity of Byron During EA Engineering 

26 Survey, 2011.................................................................................................. 3-58

27 Table 3–14. Federally Listed Species in Ogle County, Illinois............................................ 3-61

28 Table 3–15. Cultural Resources Within the Byron Site ...................................................... 3-68

29 Table 3–16. Exelon Generation Employees Residence by County .................................... 3-69

30 Table 3–17. Employment by Industry in the Byron ROI (5-year estimates 

31 2008–2012).................................................................................................... 3-70

32 Table 3–18. Major Employers in Ogle County in 2012 ....................................................... 3-71

33 Table 3–19. Estimated Income Information for the Byron ROI (5-year estimates 

34 2008–2012).................................................................................................... 3-72

35 Table 3–20. Population and Percent Growth in Byron ROI Counties 1970–2010, 

36 2012 (estimated), and Projected for 2020–2060 ............................................ 3-73

37 Table 3–21. Illinois Department of Commerce and Economic Opportunity (DCEO) 

38 Population Projections for 2000–2030............................................................ 3-73

39 Table 3–22. Demographic Profile of the Population in the Byron ROI in 2010 ................... 3-74

40 Table 3–23. 2007–2011 Estimated Seasonal Housing in Counties Located Within 

41 50 mi (80 km) of Byron................................................................................... 3-75

42 Table 3–24. Migrant Farm Workers and Temporary Farm Labor in Counties 

43 Located within 50 mi (80 km) of Byron ........................................................... 3-77
Tables

xviii

1 Table 3–25. Housing in the Byron ROI (2008−2012, 5-year estimate)............................... 3-78

2 Table 3–26. Local Public Water Supply Systems (in million gallons per day (mgd))........... 3-79

3 Table 3–27. PIAT Payments and Recipients, 2008 and 2010 ............................................ 3-80

4 Table 3–28. Property Tax Payment Comparison, All Taxing Districts Combined ............... 3-81

5 Table 3–29. Property Tax Payment Comparison, All Taxing Districts Combined ............... 3-82

6 Table 3–30. 2011 Property Tax Payment Comparison, Each Taxing District 

7 Individually..................................................................................................... 3-83

8 Table 3–31. 2012 Property Tax Payment Comparison, Each Taxing District 

9 Individually..................................................................................................... 3-84

10 Table 3–32. Major Commuting Routes in the Vicinity of Byron: 2012 AADT ..................... 3-85

11 Table 4–1. Land Use and Visual Resources Issues........................................................... 4-2

12 Table 4–2. Air Quality and Noise ....................................................................................... 4-6

13 Table 4–3. Estimated Direct Air Emissions From Operation of the Byron Proposed 

14 Action and Alternatives (Tons/Year)............................................................... 4-20

15 Table 4–4. Geology and Soils Issues............................................................................... 4-21

16 Table 4–5. Surface Water Resources Issues................................................................... 4-23

17 Table 4–6. Groundwater Issues....................................................................................... 4-25

18 Table 4–7. Terrestrial Resource Issues ........................................................................... 4-31

19 Table 4–8. Aquatic Resource Issues ............................................................................... 4-37

20 Table 4–9. Special Status Species and Habitat Issues .................................................... 4-41

21 Table 4–10. Effect Determinations for Federally Listed Species ........................................ 4-42

22 Table 4–11. Historic and Cultural Resources..................................................................... 4-46

23 Table 4–12. Socioeconomic NEPA Issues Affected by License Renewal .......................... 4-51

24 Table 4–13. Human Health Issues..................................................................................... 4-58

25 Table 4–14. Issues Related to Postulated Accidents ......................................................... 4-62

26 Table 4–15. Byron Core Damage Frequency for Internal Events ....................................... 4-65

27 Table 4–16. Breakdown of Population Dose and Offsite Economic Cost by 

28 Containment Release Mode........................................................................... 4-66

29 Table 4–17. Environmental Justice.................................................................................... 4-71

30 Table 4–18. Waste Management Issues............................................................................ 4-76

31 Table 4–19. Issues Related to the Uranium Fuel Cycle ..................................................... 4-86

32 Table 4–20. Issues Related to Decommissioning .............................................................. 4-88

33 Table 4–21. Estimated GHG Emissions From Operations at Byron Station ....................... 4-90

34 Table 4–22. Direct Uncontrolled GHG Emissions From Operation of the Proposed 

35 Action and Alternatives .................................................................................. 4-92

36 Table 4–23. Comparison of GHG Emission Inventories................................................... 4-112

37 Table 4–24. Summary of Cumulative Impacts on Resource Areas .................................. 4-114

38 Table 6–1. List of Preparers .............................................................................................. 6-2

39 Table 7–1. List of Agencies, Organizations, and Persons to Whom Copies of This 

40 SEIS Are Sent.................................................................................................. 7-1

41 Table A–1. Individuals Providing Comments During the Scoping Comment Period............ A-2

42 Table A–2. Issue Categories.............................................................................................. A-3
Tables

xix

1 Table B–1. Federal and State Requirements ..................................................................... B-3

2 Table B–2. Licenses and Permits....................................................................................... B-8

3 Table C–1. Section 7 Consultation Correspondence.......................................................... C-3

4 Table C–2. NHPA Correspondence.................................................................................... C-4

5 Table D–1. Environmental Review Correspondence .......................................................... D-2

6 Table E–1. Projects and Actions Considered in the Cumulative Impacts Analysis.............. E-2

7 Table F–1. Byron CDF for Internal Events ......................................................................... F-3

8 Table F–2. Breakdown of Population Dose and Offsite Economic Cost by 

9 Containment Release Mode............................................................................. F-4

10 Table F–3. Summary of Major PRA Models and Corresponding CDF and LERF 

11 Results............................................................................................................. F-6

12 Table F–4(a). Major Byron Unit 1 Contributors to Fire CDF.................................................. F-12

13 Table F–4(b). Major Byron Unit 2 Contributors to Fire CDF.................................................. F-13

14 Table F–5. SAMA Cost/Benefit Screening Analysis for Byron Station.............................. F-29

xxi

1 EXECUTIVE SUMMARY

2 BACKGROUND

3 By letter dated May 29, 2013, Exelon Generation Company, LLC (Exelon), submitted an 

4 application to the U.S. Nuclear Regulatory Commission (NRC) to issue renewed operating 

5 licenses for Byron Station, Units 1 and 2 (Byron), for an additional 20-year period.

6 Pursuant to Title 10 of the Code of Federal Regulations 51.20(b)(2) (10 CFR 51.20(b)(2)), the 

7 renewal of a power reactor operating license requires preparation of an environmental impact 

8 statement (EIS) or a supplement to an existing EIS. In addition, 10 CFR 51.95(c) states that, in

9 connection with the renewal of an operating license, the NRC shall prepare an EIS, which is a 

10 supplement to the Commission’s NUREG-1437, Generic Environmental Impact Statement

11 (GEIS) for License Renewal of Nuclear Plants. 

12 Upon acceptance of Exelon’s application, the NRC staff began the environmental review 

13 process described in 10 CFR Part 51 by publishing a Notice of Intent to prepare a supplemental 

14 environmental impact statement (SEIS) and conduct scoping. In preparation of this SEIS for 

15 Byron, the NRC staff performed the following:

16  conducted public scoping meetings on August 20, 2013, in Byron, Illinois;

17  conducted a site audit at Byron from September 16 to 19, 2013;

18  reviewed Exelon’s Environmental Report (ER) and compared it to the GEIS; 

19  consulted with Federal, state, and local agencies;

20  conducted a review of the issues following the guidance set forth in 

21 NUREG-1555, Standard Review Plans for Environmental Reviews for 

22 Nuclear Power Plants, Supplement 1, Revision 1: Operating License 

23 Renewal; and

24  considered public comments received during the scoping process.

25 PROPOSED ACTION

26 Exelon initiated the proposed Federal action—issuance of a renewed power reactor operating 

27 licenses—by submitting an application for license renewal of Byron, for which the existing 

28 licenses (NPF-37and NPF-66) expire on October 31, 2024, and November 6, 2026, 

29 respectively. The NRC’s Federal action is to decide whether to renew the license for an 

30 additional 20 years. In accordance with 10 CFR 2.109, if a licensee of a nuclear power plant 

31 files an application to renew an operating license at least 5 years before the expiration date of 

32 that license, the existing license will not be deemed to have expired until the safety and 

33 environmental reviews are completed and the NRC has made a final decision to either deny the 

34 application or issue a renewed license for the additional 20 years. 

35 PURPOSE AND NEED FOR ACTION

36 The purpose and need for the proposed action (issuance of renewed licenses) is to provide an 

37 option that allows for power generation capability beyond the term of the current nuclear power 

38 plant operating license to meet future system generating needs. Such needs may be 

39 determined by other energy-planning decisionmakers, such as states, operators, and, where 

40 authorized, Federal agencies (other than NRC). This definition of purpose and need reflects the 
Executive Summary

xxii

1 NRC’s recognition that, unless there are findings in the safety review required by the Atomic 

2 Energy Act or findings in the National Environmental Policy Act (NEPA) environmental analysis 

3 that would lead the NRC to reject a license renewal application, the NRC does not have a role in 

4 the energy-planning decisions as to whether a particular nuclear power plant should continue to 

5 operate.

6 ENVIRONMENTAL IMPACTS OF LICENSE RENEWAL

7 The SEIS evaluates the potential environmental impacts of the proposed action. The 

8 environmental impacts from the proposed action are designated as SMALL, MODERATE, or 

9 LARGE. As set forth in the GEIS, Category 1 issues are those that meet all of the following 

10 criteria:

11 • The environmental impacts associated with the issue 

12 are determined to apply either to all plants or, for some 

13 issues, to plants having a specific type of cooling 

14 system or other specified plant or site characteristics.

15 • A single significance level (i.e., SMALL, MODERATE, 

16 or LARGE) has been assigned to the impacts, except 

17 for collective offsite radiological impacts from the fuel 

18 cycle and from high-level waste and spent fuel

19 disposal.

20 • Mitigation of adverse impacts associated with the issue 

21 is considered in the analysis, and it has been 

22 determined that additional plant-specific mitigation

23 measures are likely not to be sufficiently beneficial to 

24 warrant implementation.

25 For Category 1 issues, no additional site-specific analysis is required in this SEIS unless new 

26 and significant information is identified. Chapter 4 of this SEIS presents the process for 

27 identifying new and significant information. Site-specific issues (Category 2) are those that do 

28 not meet one or more of the criteria for Category 1 issues; therefore, an additional site-specific 

29 review for these nongeneric issues is required, and the results are documented in the SEIS. 

30 Neither Exelon nor NRC identified information that is both new and significant related to 

31 Category 1 issues that would call into question the conclusions in the GEIS. This conclusion is 

32 supported by the NRC’s review of the applicant’s ER and other documentation relevant to the 

33 applicant’s activities, the public scoping process and substantive comments raised, and the 

34 findings from the environmental site audit conducted by the NRC staff. The NRC staff, 

35 therefore, relies upon the conclusions of the GEIS for all Category 1 issues applicable to Byron.

36 Table ES-1 summarizes the Category 2 issues relevant to Byron as well as the NRC staff’s 

37 findings related to those issues. If the NRC staff determined that there were no Category 2 

38 issues applicable for a particular resource area, the findings of the GEIS, as documented in 

39 Appendix B to Subpart A of 10 CFR Part 51, are incorporated for that resource area. 

SMALL: Environmental 

effects are not detectable or 

are so minor that they will 

neither destabilize nor 

noticeably alter any important 

attribute of the resource.

MODERATE: Environmental 

effects are sufficient to alter 

noticeably, but not to 

destabilize, important attributes 

of the resource.

LARGE: Environmental 

effects are clearly noticeable 

and are sufficient to destabilize 

important attributes of the 

resource.
Executive Summary

xxiii

1 Table ES–1. Summary of NRC Conclusions Relating to Site-Specific Impacts of

2 License Renewal

Resource Area Relevant Category 2 Issues Impacts

Land Use None SMALL

Air Quality None SMALL

Geology and Soils None SMALL

Surface Water Resources 

Surface water use conflicts (plants with 

cooling ponds or cooling towers using 

makeup water from a river)

SMALL

Groundwater Resources 

Groundwater use conflicts (plants with 

closed-cycle cooling systems that withdraw 

makeup water from a river)

Radionuclides released to groundwater

SMALL

SMALL

Terrestrial Resources

Effects on terrestrial resources (noncooling 

system impacts)

Water use conflicts with terrestrial resources 

(plants with cooling ponds or cooling towers 

using makeup water from a river)

SMALL

SMALL

Aquatic Resources Water use conflicts with aquatic resources SMALL

Special Status Species Threatened or endangered species No effect (a)

Historic and Cultural Historic and cultural resources No adverse effect (b)

Socioeconomics None SMALL

Human Health 

Microbiological hazards to the public health

(plants with cooling ponds or canals or 

cooling towers that discharge to a river)

Electric shock hazards

SMALL

SMALL

Environmental Justice Minority and low-income populations See note below (c)

Waste Management None SMALL

Cumulative Impacts

Air Quality and Noise

Geology and Soils

Water Resources

Terrestrial Ecology

Aquatic Resources

Historic and Cultural Resources

Socioeconomic

Human Health

Environmental Justice

Waste Management

Global Climate Change

SMALL

SMALL

SMALL

SMALL-MODERATE

MODERATE

SMALL

SMALL

SMALL

See note below (c)

SMALL

MODERATE
Executive Summary

xxiv

Resource Area Relevant Category 2 Issues Impacts

(a)

For Federally protected species, the NRC reports the effects from continued operation of Byron during the license 

renewal period in terms of its Endangered Species Act (ESA) findings of “no effect,” “may effect, but not likely to 

adversely effect,” or “may affect, and is likely to adversely affect.”

(b)

The National Historic Preservation Act of 1966, as amended (NHPA) requires Federal agencies to consider the 

effects of their undertakings on historic properties. (c)

 There would be no disproportionately high and adverse impacts to minority and low-income populations and 

subsistence consumption from continued operation of Byron during the license renewal period and from 

cumulative impacts.

1 SEVERE ACCIDENT MITIGATION ALTERNATIVES 

2 Since the staff had not previously considered severe accident mitigation alternatives (SAMA) in 

3 an environmental impact statement or in an environmental assessment for Byron, 

4 10 CFR 51.53(c)(3)(ii)(L) requires a consideration of alternatives to mitigate severe accidents in 

5 the course of the license renewal review. SAMAs are potential ways to reduce the risk or 

6 potential impacts of uncommon, but potentially severe accidents, and they may include changes 

7 to plant components, systems, procedures, and training.

8 The NRC staff reviewed Exelon’s ER evaluation of potential SAMAs. Based on the staff’s 

9 review, the NRC staff concluded that none of the potentially cost beneficial SAMAs relate to 

10 adequately managing the effects of aging during the period of extended operation. Therefore, 

11 they need not be implemented as part of the license renewal, pursuant to 10 CFR Part 54.

12 ALTERNATIVES

13 The NRC staff considered the environmental impacts associated with alternatives to license 

14 renewal. These alternatives include other methods of power generation and not renewing the 

15 Byron operating license (the no-action alternative). The feasible and commercially viable 

16 replacement power alternatives considered were:

17  new nuclear;

18  integrated gasification combined cycle (IGCC);

19  natural gas combined-cycle (NGCC); 

20  a combination of NGCC, wind, and solar power; and

21  purchased power.

22 The NRC staff initially considered a number of additional alternatives for analysis as alternatives 

23 to the license renewal of Byron; these were later dismissed because of technical, resource 

24 availability, or commercial limitations that currently exist and that the NRC staff believes are 

25 likely to continue to exist when the existing Byron licenses expire. The no-action alternative and 

26 the effects it would have were also considered by the NRC staff. 

27 Where possible, the NRC staff evaluated potential environmental impacts for these alternatives

28 located both at the Byron site and at some other unspecified alternate location. Alternatives 

29 considered, but dismissed, were:

30  energy conservation and energy efficiency;

31  solar power;
Executive Summary

xxv 

1  wind power; 

2  biomass power;

3  hydroelectric power;

4  wave and ocean energy;

5  fuel cells;

6  delayed retirement;

7  geothermal power;

8  municipal solid waste; 

9  petroleum; and

10  supercritical pulverized coal. 

11 The NRC staff evaluated each alternative using the same resource areas that were used in 

12 evaluating impacts from license renewal.

13 PRELIMINARY RECOMMENDATION

14 The NRC staff’s preliminary recommendation is that the adverse environmental impacts of 

15 license renewal for Byron are not so great that preserving the option of license renewal for 

16 energy-planning decisionmakers would be unreasonable. This recommendation is based on the 

17 following:

18  the analyses and findings in the GEIS; 

19  the ER submitted by Exelon;

20  the NRC staff’s consultation with Federal, state, and local agencies;

21  the NRC staff’s independent environmental review; and

22  the NRC staff’s consideration of public comments received during the scoping

23 process. 

xxvii 

1 ABBREVIATIONS AND ACRONYMS

2 μL/L microliter(s) per liter

3 μm micrometer(s)

4 AADT average annual daily traffic

5 ac acre(s)

6 AC alternating current

7 ACC averted cleanup and decontamination costs

8 ACHP Advisory Council on Historic Preservation

9 ADAMS Agencywide Documents Access and Management System

10 AEA Atomic Energy Act of 1954 (as amended)

11 AEC U.S. Atomic Energy Commission

12 AFW auxiliary feedwater

13 ALARA as low as is reasonably achievable

14 AMSAC ATWS mitigating system actuation circuitry

15 ANL Argonne National Laboratory

16 ANS American Nuclear Society

17 AOC averted offsite property damage costs

18 AOE averted occupational exposure

19 AOSC averted onsite costs

20 AP auxiliary power

21 APE averted public exposure

22 averted potential exposure

23 AQCR Air Quality Control Region

24 ARERR Annual Radiological Effluent Release Report

25 ASA Acoustical Society of America

26 ASLB Atomic Safety and Licensing Board (NRC)

27 ASME American Society of Mechanical Engineers

28 ATWS anticipated transient(s) without scram

29 AWEA American Wind Energy Association

30 AWT Association of Water Technologies

31 BACT best available control technology

32 BEA Bureau of Economic Analysis

33 BLH BLH Technologies, Inc.

34 BLM Bureau of Land Management
Abbreviations and Acronyms

xxviii 

1 BLS Bureau of Labor Statistics

2 BMP best management practice

3 BOEM Bureau of Ocean Energy Management

4 BP before present

5 BSER best system of emission reduction

BTU/ft3 6 British thermal unit(s) per cubic foot

7 Byron Byron Station, Units 1 and 2

8 CAA Clean Air Act

9 CAES compressed air energy storage

10 CAIR Clean Air Interstate Rule

11 Callaway Unit 2 Callaway Nuclear Power Plant Unit 2

12 CB&I Chicago Bridge & Iron

13 CCS carbon capture and storage

14 CCW component cooling water

15 CDF core damage frequency

16 CEQ Council on Environmental Quality

17 Ceq/kWh carbon equivalent per kilowatt-hour

18 CET containment event tree

19 CFE early containment failure

20 CFR Code of Federal Regulations

21 cfs cubic foot (feet) per second

22 CH4 methane

23 CISEH Center for Invasive Species and Ecosystem Health

24 CLB current licensing basis/bases

25 cm centimeter(s)

26 CO carbon monoxide

27 CO2 carbon dioxide

28 CO2/MWh carbon dioxide per megawatt hour

29 COL combined license

30 ComEd Commonwealth Edison

31 CPE catch per effort

32 CRA Conestoga-Rovers & Associates

33 CRMP Cultural Resource Management Plant

34 CRMP Cultural Resource Management Plant

35 CSAPR Cross-State Air Pollution Rule
Abbreviations and Acronyms

xxix

1 CVCS chemical and volume control system

2 CWA Clean Water Act

3 DAW dry active waste

4 dBA decibels adjusted

5 DBA design-basis accident

6 DCEO Department of Commerce and Economic Opportunity

7 div. Division

8 DLOOP dual unit loss(es) of offsite power

9 DMS Diverse Mitigation System

10 DNPS Dresden Nuclear Power Station

11 DOE Department of Energy

12 DSEIS draft supplemental environmental impact statement

13 DSIRE Database of State Incentives for Renewables & Efficiency

14 DSM demand-side management

15 EA environmental assessment

16 EAI Environmental Analysts, Inc.

17 EAV equalized assessed value

18 ECCS emergency core cooling system

19 EcoCAT Ecological Compliance Assessment Tool

20 EFH essential fish habitat

21 EIA Energy Information Administration

22 EIS environmental impact statement

23 ELF extremely low frequency

24 ELPC Environmental Law and Policy Center

25 Elv. Elevation

26 EMF electromagnetic field

27 EO Executive Order

28 EPA U.S. Environmental Protection Agency

29 EPRI Electric Power Research Institute

30 EPZ emergency planning zone

31 ER Environmental Report

32 ERC Energy Recovery Council

33 ER-O Environmental Report for Byron operation

34 ES Environmental Services

35 ESA Endangered Species Act of 1973, as amended
Abbreviations and Acronyms

xxx 

1 ESF engineered safety feature

2 ESFAS engineered safety features actuation system

3 ESI Ecological Specialists, Inc.

4 ESP early site permit

5 ESW emergency service water

6 ET Earth Tech, Inc.

7 Exelon Exelon Generation Company, LLC

8 F&O fact and observation

9 FD fresh dead shell(s)

10 FERC Federal Energy Regulatory Commission

11 Fermi Unit 3 Enrico Fermi Atomic Power Plant, Unit 3

12 FES final environmental statement

13 FES-C Final Environmental Statement for Byron construction

14 FES-O Final Environmental Statement for Byron operation

15 FESOP Federally Enforceable State Operating Permit

16 FHWA Federal Highway Administration

17 FIVE fire-induced vulnerability evaluation

18 FR Federal Register

19 FRN Federal Register notice

20 ft foot (feet) 

ft2 21 square foot (feet)

ft3 22 cubic foot (feet)

23 FW feedwater

24 FWCA Fish and Wildlife Coordination Act of 1934, as amended

25 FWS U.S. Fish and Wildlife Service

26 g gram(s)

27 gal gallon(s) 

28 GE General Electric

29 GEIS generic environmental impact statement

30 GHG greenhouse gas

31 GI generic issue

32 GL generic letter

33 gpd gallon(s) per day

34 gpm gallon(s) per minute

35 Gt gigatonne(s)
Abbreviations and Acronyms

xxxi 

1 GWPS gaseous waste processing system

2 H2O water vapor

3 ha hectare(s)

4 HAI healthcare-associated infections

5 HAP hazardous air pollutant

6 HCLPF high confidence in low probability of failure

7 HEP human error probability

8 HFE human failure event

9 HFO high winds, floods, and other

10 hr hour(s)

11 HRA human reliability analysis

12 HRSG heat recovery steam generator

13 HUD U.S. Department of Housing and Urban Development

14 HX heat exchanger

15 IAC Illinois Administrative Code

16 IBA Important Bird Area

17 IDNR Illinois Department of Natural Resources

18 IDOT Illinois Department of Transportation

19 IDPH Illinois Department of Public Health

20 IEA International Energy Agency

21 IEMA Illinois Emergency Management Agency

22 IEPA Illinois Environmental Protection Agency

23 IESPB Illinois Endangered Species Protection Board

24 IGCC integrated gasification combined cycle

25 IHPA Illinois Historic Preservation Agency

26 ILCS Illinois Compiled Statutes

27 ILGA Illinois General Assembly

28 in. inch(es)

29 INEEL Idaho National Engineering and Environmental Laboratory

30 INHS Illinois Natural History Survey

31 Invenergy Invenergy, LLC

32 IPCC Intergovernmental Panel on Climate Change

33 IPE individual plant examination

34 IPEEE individual plant examination(s) of external events

35 ISBE Illinois State Board of Education
Abbreviations and Acronyms

xxxii 

1 ISD Integrated Surface Data

2 ISFSI independent spent fuel storage installation

3 ISGS Illinois State Geological Survey

4 ISLOCA interfacing-systems loss-of-coolant accident

5 ISM Illinois State Museum

6 JHEP joint human error probability

7 km kilometer(s)

km2 8 square kilometer(s)

9 kW kilowatt(s)

10 kWe kilowatt(s) electric

11 L liter(s)

12 L live individual(s)

13 L/min liter(s) per minute

14 L/s liter(s) per second

15 lb pound(s)

16 Ldn day-night average sound level—the 24-hour A-weighted 

17 equivalent sound level, with a 10-decibel penalty applied to 

18 nighttime levels

19 Leq equivalent continuous noise level

20 LER large, early release

21 LERF large early release frequency

22 LIDAR Light Detection and Ranging

23 LLW low-level radioactive waste

24 LMFW loss of main feedwater

25 LOCA loss-of-coolant accident

26 LOOP loss(es) of offsite power

27 Lpd liters per day

28 LRA license renewal application

29 m/s meter(s) per second

m2 30 square meter(s)

m3 31 cubic meter(s)

m3 32 /s cubic meter(s) per second

33 MAAP Modular Accident Analysis Program

34 MACCS2 MELCOR Accident Consequence Code System 2

35 MACR maximum averted cost-risk
Abbreviations and Acronyms

xxxiii 

1 MAE Center Mid-America Earthquake Center

2 MATS Mercury and Air Toxics Standards

3 MBTA Migratory Bird Treaty Act

4 MCR main control room

5 MDNR Minnesota Department of Natural Resources

6 MELCOR Methods for Estimation of Leakages and Consequences of 

7 Releases

8 mg/L milligram(s) per liter

9 mgd million gallons per day

10 mgy million gallons per year

11 mGy milligray

12 mi mile(s)

mi2 13 square mile(s)

14 MISO Midcontinent Independent System Operator, Inc.

15 MMPA Marine Mammal Protection Act

16 MMSHT Michigan Mine Safety & Health Training

17 MMT million metric tons

18 MODNR Missouri Department of Natural Resources

19 MOV motor-operated valve

20 mph mile(s) per hour

21 mrad millirad

22 mrem millirem

23 MSA Magnuson–Stevens Fishery Conservation and Management Act, 

24 as amended through 2006

25 mSv millisievert

26 MT metric ton(s)

27 MUR measurement uncertainty recapture

28 MW megawatt(s)

29 MWe megawatt(s) electric

30 MWh megawatt hour(s)

31 MWt megawatt(s) thermal

32 N2O nitrous oxide

33 NAAQS National Ambient Air Quality Standards

34 NAH North American Hydro

35 NARUC National Association of Regulatory Utility Commissioners
Abbreviations and Acronyms

xxxiv 

1 NASS National Agricultural Statistics Service

2 NCDC National Climatic Data Center

3 NCES National Center for Education Statistics

4 NEA Nuclear Energy Agency

5 NEI Nuclear Energy Institute

6 NEIS National Energy Information Service

7 NEPA National Environmental Policy Act

NESC® National Electrical Safety Code® 8 

9 NETL National Energy Technology Laboratory

10 NGCC natural gas combined-cycle 

11 NHL National historic landmark

12 NHPA National Historic Preservation Act of 1966, as amended

13 NIEHS National Institute of Environmental Health Sciences

14 NMFS National Marine Fisheries Service (of NOAA)

15 NO2 nitrogen dioxide

16 NOx nitrogen oxide(s)

17 NP National park

18 NPDES National Pollutant Discharge Elimination System

19 NPL National Priorities List

20 NPS National Park Service

21 NRC U.S. Nuclear Regulatory Commission

22 NREL National Renewable Energy Laboratory

23 NRHP National Register of Historic Places

24 NRR Nuclear Reactor Regulation, Office of (NRC)

25 NSR New Source Review

26 NUREG NRC technical report designation

27 NWCC National Wind Coordinating Committee

28 O3 ozone

29 OCPZD Ogle County Planning & Zoning Department

30 ODCM Offsite Dose Calculation Manual

31 OECD Organisation for Economic Co-operation and Development

32 OECR offsite economic cost risk

33 ORNL Oak Ridge National Laboratory

34 OSH Occupational Safety and Health

35 OSHA Occupational Safety & Health Administration
Abbreviations and Acronyms

xxxv 

1 PAM primary amoebic meningoencephalitis

2 Pb lead

3 PCB polychlorinated biphenyl

4 pCi/L picocurie(s) per liter

5 PDR population dose risk

6 PDS plant damage state

7 PEIS programmatic environmental impact statement

8 PFC perfluorocarbon

9 PIAT payment in addition to taxes

10 PIMW potentially infectious medical waste

11 PIN Property Index Number

12 PJM PJM Interconnection, LLC

13 PL public law

14 PLS-CADDTM Power Line Systems—Computer Aided Design and Drafting

15 PM particulate matter

16 PM10 particulate matter with aerodynamic diameters of 10 micrometers 

17 or less

18 PM2.5 particulate matter with aerodynamic diameters of 2.5 micrometers 

19 or less

20 PNNL Pacific Northwest National Laboratory

21 PONAR sampling device used to study composition of lake bottom or river 

22 bottom, named after Great Lakes scientists Powers, Ogle, Noble, 

23 Ayers, and Robertson

24 PORV power-operated relief valve

25 PPA Pollution Prevention Act of 1990

26 ppm parts per million

27 PRA probabilistic risk assessment

28 PSD prevention of significant deterioration

29 PTE potential to emit

30 PV photovoltaic

31 PWR pressurized-water reactor

32 RAI request(s) for additional information

33 RCP reactor coolant pump

34 RCRA Resource Conservation and Recovery Act

35 RDS Research and Development Solutions, LLC

36 rem roentgen equivalent(s) man
Abbreviations and Acronyms

xxxvi 

1 REMP radiological environmental monitoring program

2 RES Office of Nuclear Regulatory Research

3 RHR residual heat removal

4 Regional Haze Rule

5 RM river mile

6 ROI region(s) of influence

7 ROW right-of-way

8 RPC replacement power cost

9 RPS reactor protection system

10 RPV reactor pressure vessel

11 RRW risk reduction worth

12 RTO Regional Transmission Organization

13 RWST refueling water storage tank

14 SAFSTOR safe storage, also called deferred dismantling; a decommissioning 

15 strategy in which the nuclear facility is maintained and monitored 

16 in a condition that allows the radioactivity to decay before 

17 dismantling the plant and decontaminating the property

18 SAMA severe accident mitigation alternative

19 SAR safety analysis report

20 SAT system auxiliary transformer

21 SBO station blackout

22 SCR selective catalytic reduction

23 SCPC supercritical pulverized coal

24 SDCI State Data Center of Iowa

25 SDWIS Safe Drinking Water Information System

26 SEIS supplemental environmental impact statement

27 SER safety evaluation report

28 SF6 sulfur hexafluoride

29 SFU Simon Fraser University

30 SG steam generator

31 SGTR steam generator tube rupture

32 SI safety injection

33 SIP State Implementation Plan

34 SMA seismic margin assessment

35 SO2 sulfur dioxide

36 SOx sulfur oxide(s)
Abbreviations and Acronyms

xxxvii 

1 spp. species (plural)

2 SR supporting requirement

3 SRM staff requirements memorandum (memoranda)

4 SSC structure, system, and component

5 SSEL Safe Shutdown Equipment List

6 Sv sievert(s)

7 SW service water

8 SX essential service water

9 t U.S. short ton(s)

10 TAC technical assignment control

11 TEEIC Tribal Energy and Environmental Information Clearinghouse

12 Teledyne Teledyne Brown Engineering Environmental Services

13 Tg teragram(s)

14 TS technical specification

15 U.S. United States

16 U.S.C. United States Code

17 UAT unit auxiliary transformer

18 UFSAR updated final safety analysis report

19 USACE United States Army Corps of Engineers

20 USCB U.S. Census Bureau

21 USDA U.S. Department of Agriculture

22 USDHHS U.S. Department of Health and Human Services

23 USFS U.S. Forest Service

24 USGCRP U.S. Global Change Research Program

25 USGS U.S. Geological Survey

26 Vogtle Units 3 and 4 Vogtle Electric Generating Plant, Units 3 and 4

27 yd yard(s)

yd3 28 cubic yard(s)

W/m2 29 watt(s) per square meter

30 WAPA Western Area Power Administration

31 WAW wet active waste

32 WCAP Westinghouse Commercial Atomic Power

33 WDOA Wisconsin Department of Administration

34 WHC Wildlife Habitat Council

35 WSA wet gas sulfuric acid
Abbreviations and Acronyms

xxxviii 

1 yd yard(s) 

yd3 2 cubic yard(s)

3 yr year
1-1 

1 1.0 INTRODUCTION

2 Under the U.S. Nuclear Regulatory Commission’s (NRC’s) environmental protection regulations 

3 in Title 10, Part 51, of the Code of Federal Regulations (10 CFR 51)—which implement the 

4 National Environmental Policy Act (NEPA)—issuance of a new nuclear power plant operating 

5 license requires the preparation of an environmental impact statement (EIS).

6 The Atomic Energy Act of 1954 (AEA) specified that licenses for commercial power reactors can 

7 be granted for up to 40 years. NRC regulations (10 CFR 54.31) allow for an option to renew a 

8 license for up to an additional 20 years. The initial 40-year licensing period was based on 

9 economic and antitrust considerations rather than on technical limitations of the nuclear facility.

10 The decision to seek a license renewal rests entirely with nuclear power facility owners and, 

11 typically, is based on the facility’s economic viability and the investment necessary to continue 

12 to meet NRC safety and environmental requirements. The NRC makes the decision to grant or 

13 deny license renewal based on whether the applicant has demonstrated that the environmental 

14 and safety requirements in the agency’s regulations can be met during the period of extended 

15 operation.

16 1.1 Proposed Federal Action

17 Exelon Generation Company, LLC (Exelon), initiated the proposed Federal action by submitting 

18 an application for license renewal of Byron Station, Units 1 and 2 (Byron), for which the existing 

19 licenses (NPF-37and NPF-66) expire on October 31, 2024, and November 6, 2026. The NRC’s 

20 Federal action is to decide whether to renew the license for an additional 20 years.

21 1.2 Purpose and Need for Proposed Federal Action

22 The purpose and need for the proposed action (issuance of a renewed license) is to provide an 

23 option that allows for power generation capability beyond the term of a current nuclear power 

24 plant operating license to meet future system generating needs, as such needs may be 

25 determined by other energy-planning decisionmakers. This definition of purpose and need 

26 reflects the NRC’s recognition that, unless there are findings in the safety review required by the 

27 AEA or findings in the NEPA environmental analysis that would lead the NRC to reject a license 

28 renewal application (LRA), the NRC does not have a role in the energy-planning decisions of 

29 state regulators and utility officials as to whether a particular nuclear power plant should 

30 continue to operate.

31 1.3 Major Environmental Review Milestones

32 Exelon submitted an Environmental Report (ER) (Exelon 2013a) as part of its 

33 LRA (Exelon 2013b) in May 2013. After reviewing the LRA and ER for sufficiency, the NRC 

34 staff published a Federal Register Notice of Acceptability and Opportunity for Hearing 

35 (78 FR 44603) on July 24, 2013. Then, on August 6, 2013, the NRC published another notice in 

36 the Federal Register (78 FR 47800) on the intent to conduct scoping, thereby beginning the 

37 60-day scoping period.

38 Two public scoping meetings were held on August 20, 2013, in Byron, Illinois (NRC 2013a). 

39 The comments received during the scoping process are presented in “Environmental Impact 

40 Statement, Scoping Process, Summary Report,” published in May 2014 (NRC 2014). The 

41 scoping process summary report presents NRC responses to comments that the staff 
Introduction

1-2 

1 considered to be out of scope of the environmental license renewal review. The comments 

2 considered to be within the scope of the environmental license renewal review and the NRC 

3 responses are presented in Appendix A of this supplemental environmental impact statement 

4 (SEIS).

5 To independently verify information provided in the ER, NRC staff conducted a site audit at 

6 Byron in September 2013. During the site audit, NRC staff met with plant personnel, reviewed 

7 specific documentation, toured the facility, and met with interested local agencies. A summary 

8 of that site audit and the attendees is contained in “Summary of Site Audit in Support to the 

9 Environmental Review of the License Renewal Application for Byron Station, Units 1 and 2, 

10 (TAC Nos. MF1834 and MF1835)” published October 3, 2013 (NRC 2013c).

11 Upon completion of the scoping period and site audit, NRC staff compiled its findings in a draft 

12 SEIS. This document is made available for public comment for 75 days. During this time, NRC 

13 staff will host public meetings and collect public comments. Based on the information gathered, 

14 the NRC staff will amend the draft SEIS findings, as necessary, and publish the final SEIS. 

15 Figure 1–1 shows the major milestones of the NRC’s LRA environmental review.

16 Figure 1–1. Environmental Review Process

17

18 The NRC has established a license renewal process that can be completed in a reasonable 

19 period of time with clear requirements to ensure safe plant operation for up to an additional 

20 20 years of plant life. The NRC staff conducts the safety review simultaneously with the 

21 environmental review. The staff documents the findings of the safety review in a safety 

22 evaluation report (SER). The findings in the SEIS and the SER are both factors in the NRC’s 

23 decision to either grant or deny the issuance of a renewed license. 
Introduction

1-3 

1 1.4 Generic Environmental Impact Statement

2 The NRC staff performed a generic assessment of the environmental impacts associated with 

3 license renewal to improve the efficiency of its license renewal review. The Generic 

4 Environmental Impact Statement for License Renewal of Nuclear Power Plants, NUREG-1437 

5 (GEIS), (NRC 1996, 1999, 2013b), documented the results of the staff’s systematic approach to 

6 evaluate the environmental consequences of renewing the licenses of individual nuclear power 

7 plants and operating them for an additional 20 years. The staff analyzed in detail and resolved 

8 those environmental issues that could be resolved generically in the GEIS. The GEIS was 

9 originally issued in 1996, Addendum 1 to the GEIS was issued in 1999, and Revision 1 to the 

10 GEIS was issued in 2013. Unless otherwise noted, all references to the GEIS include the GEIS, 

11 Addendum 1, and Revision 1. 

12 The GEIS establishes separate environmental impact issues for the NRC staff to independently 

13 verify. Of these issues, the NRC staff determined that some generic issues are generic to all 

14 plants (Category 1). Other issues do not lend themselves to generic consideration (Category 2 

15 or uncategorized). The staff evaluated these issues on a site-specific basis in the SEIS. 

16 Appendix B to Subpart A of 10 CFR 51 provides a summary of the staff findings in the GEIS.

17 For each potential environmental issue, in the GEIS the NRC staff:

18  describes the activity that affects the environment,

19  identifies the population or resource that is affected,

20  assesses the nature and magnitude of the impact on the affected population 

21 or resource,

22  characterizes the significance of the effect for both beneficial and adverse 

23 effects,

24  determines whether the results of the analysis apply to all plants, and

25  considers whether additional mitigation measures would be warranted for 

26 impacts that would have the same significance level for all plants.

27 The NRC’s standard of significance for impacts was established using the Council on 

28 Environmental Quality terminology for “significant.” The NRC established three levels of 

29 significance for potential impacts—SMALL, MODERATE, and LARGE, as defined below.

30 SMALL: Environmental effects are not 

31 detectable or are so minor that they will neither 

32 destabilize nor noticeably alter any important 

33 attribute of the resource.

34 MODERATE: Environmental effects are 

35 sufficient to alter noticeably, but not to 

36 destabilize, important attributes of the resource.

37 LARGE: Environmental effects are clearly 

38 noticeable and are sufficient to destabilize important attributes of the resource.

Significance indicates the importance of likely 

environmental impacts and is determined by 

considering two variables: context and intensity. 

Context is the geographic, biophysical, and social 

context in which the effects will occur.

Intensity refers to the severity of the impact, in 

whatever context it occurs.
Introduction

1-4 

1 The GEIS includes a determination of whether the analysis of the environmental issue could be 

2 applied to all plants and whether additional mitigation measures would be warranted. Issues 

3 are assigned a Category 1 or a Category 2 designation. As set forth in the GEIS, Category 1 

4 issues are those that meet the following criteria:

5  The environmental impacts associated with the issue have been determined 

6 to apply either to all plants or, for some issues, to plants having a specific 

7 type of cooling system or other specified plant or site characteristics. 

8  A single significance level (i.e., SMALL, MODERATE, or LARGE) has been 

9 assigned to the impacts (except for collective offsite radiological impacts from 

10 the fuel cycle and from high-level waste and spent fuel disposal).

11  Mitigation of adverse impacts associated with the issue has been considered 

12 in the analysis, and it has been determined that additional plant-specific 

13 mitigation measures are likely not to be sufficiently beneficial to warrant 

14 implementation.

15 For generic issues (Category 1), no additional site-specific analysis is required in the SEIS 

16 unless new and significant information is identified. The process for identifying new and 

17 significant information for site-specific analysis is presented in Chapter 4. Site-specific issues 

18 (Category 2) are those that do not meet one or more of the criteria of Category 1 issues; 

19 therefore, additional site-specific review for these issues is required. A site-specific analysis is 

20 required for 17 of those 78 issues evaluated in the GEIS. Figure 1–2 illustrates this process. 

21 The results of that site-specific review are documented in the SEIS.
Introduction

1-5 

1 Figure 1–2. Environmental Issues Evaluated for License Renewal

2 In the GEIS, the NRC evaluated 78 issues. 

3 A site-specific analysis is required for 17 of those 78 issues. 

4 

5 1.5 Supplemental Environmental Impact Statement

6 The SEIS presents an analysis that considers the environmental effects of the continued 

7 operation of Byron, alternatives to license renewal, and mitigation measures for minimizing 

8 adverse environmental impacts. Chapter 4 contains analysis and comparison of the potential 

9 environmental impacts from alternatives, while Chapter 5 presents the recommendation of the 

10 NRC on whether the environmental impacts of license renewal are so great that preserving the 

11 option of license renewal would be unreasonable. The final recommendation will be made after 

12 consideration of comments received on the draft SEIS during the public comment period.

13 In the preparation of the SEIS for Byron, the NRC staff carried out the following activities:

14  reviewed the information provided in Exelon’s ER;

15  consulted with Federal agencies, state and local agencies, and tribal nations; 
Introduction

1-6 

1  conducted an independent review of the issues during site audit; and

2  considered the public comments received for the review (during the scoping

3 process).

4 New information can be identified from many 

5 sources, including the applicant, the NRC, other 

6 agencies, or public comments. If a new issue is 

7 revealed, it is first analyzed to determine whether 

8 it is within the scope of the license renewal 

9 environmental evaluation. If the new issue is not addressed in the GEIS, the NRC staff would 

10 determine the significance of the issue and document the analysis in the SEIS.

11 1.6 Decisions to be Supported by the SEIS

12 The decision to be supported by the SEIS is whether to renew the operating licenses for Byron 

13 for an additional 20 years. The NRC decision standard is specified in 10 CFR 51.103(a)(5): 

14 In making a final decision on a license renewal action pursuant to Part 54 of this 

15 chapter, the Commission shall determine whether or not the adverse 

16 environmental impacts of license renewal are so great that preserving the option 

17 of license renewal for energy planning decisionmakers would be unreasonable.

18 There are many factors that the NRC takes into consideration when deciding whether to renew 

19 the operating license of a nuclear power plant. The analyses of environmental impacts 

20 evaluated in this GEIS will provide the NRC’s decisionmaker (in this case, the Commission) with 

21 important environmental information for use in the overall decisionmaking process. There are 

22 also decisions outside the regulatory scope of license renewal that cannot be made on the basis 

23 of the GEIS analysis. These decisions include the following issues: changes to plant cooling 

24 systems, disposition of spent nuclear fuel, emergency preparedness, safeguards and security, 

25 need for power, and seismicity and flooding (NRC 2013b).

26 1.7 Cooperating Agencies

27 During the scoping process, no Federal, state, or local agencies were identified as cooperating 

28 agencies in the preparation of this SEIS.

29 1.8 Consultations

30 The Endangered Species Act of 1973, as amended; the Magnuson–Stevens Fisheries

31 Conservation and Management Act of 1996, as amended (MSA); and the National Historic 

32 Preservation Act of 1966, as amended (NHPA), require that Federal agencies consult with 

33 applicable state and Federal agencies and groups before taking action that may affect 

34 endangered species, fisheries, or historic and archaeological resources, respectively. The NRC 

35 consulted with the following agencies and groups; Appendix D provides a discussion of the 

36 consultation documents:

37  U.S. Fish and Wildlife Service (FWS);

38  Illinois Historic Preservation Agency; 

39  Advisory Council on Historic Preservation; 

40  Ho-Chunk Nation;

41  Miami Tribe of Oklahoma;

New and significant information - To merit 

additional review, information must be both “new” 

and “significant,” and it must bear on the proposed 

action or its impacts. 
Introduction

1-7 

1  Peoria Tribe of Indians of Oklahoma;

2  Citizen Potawatomi Nation;

3  Sac and Fox Tribe of the Mississippi in Iowa/Meswaki Nation;

4  Sac and Fox Nation of Missouri in Kansas and Nebraska;

5  Sac and Fox Nation;

6  Pokagon Band of Potawatomi;

7  Forest County Potawatomi;

8  Hannahville Indian Community, Band of Potawatomi;

9  Prairie Band Potawatomi Nation;

10  Winnebago Tribe of Nebraska;

11  Kickapoo Tribe in Kansas; and

12  Kickapoo Tribe of Oklahoma.

13 1.9 Correspondence

14 During the course of the environmental review, the NRC staff contacted Federal, state, regional, 

15 local, and tribal agencies listed in Section 1.8. Appendices C and D contain a chronological list 

16 of all documents sent and received during the environmental review. Appendix D lists the 

17 correspondence associated with Endangered Species Act of 1973, as amended; the MSA; and 

18 the NHPA. Appendix C lists all other correspondence.

19 1.10 Status of Compliance

20 Exelon is responsible for complying with all NRC regulations and other applicable Federal, 

21 state, and local requirements. Appendix F of the GEIS describes some of the major applicable 

22 Federal statutes. There are numerous permits and licenses issued by Federal, state, and local 

23 authorities for activities at Byron. Appendix B contains further information about Byron status of 

24 compliance.

25 1.11 Related State and Federal Activities

26 The NRC reviewed the possibility that activities of other Federal agencies might impact the 

27 renewal of the operating license for Byron. There are no Federal projects that would make it 

28 necessary for another Federal agency to become a cooperating agency in the preparation of 

29 this SEIS. 

30 There are no known American Indian lands within 50 mi (80 km) of Byron. There are 

31 two Federally owned facilities within 50 mi of Byron: (1) Fermi National Accelerator Laboratory 

32 and (2) Upper Mississippi River Wildlife and Fish Refuge.

33 The NRC is required under Section 102(2)(C) of NEPA to consult with and obtain the comments 

34 from any Federal agency that has jurisdiction by law or special expertise with respect to any 

35 environmental impact involved in the subject matter of the EIS. For example, during the course 

36 of preparing the SEIS, the NRC consulted with the FWS. A complete list of consultation 

37 correspondences is listed in Appendix D. 
Introduction

1-8 

1 1.12 References 

2 10 CFR 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental protection 

3 regulations for domestic licensing and related regulatory functions.”

4 10 CFR 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for renewal 

5 of operating licenses for nuclear power plants.”

6 78 FR 44603. U.S. Nuclear Regulatory Commission. “Byron Nuclear Station, Units 1 and 2, and 

7 Braidwood Nuclear Station, Units 1 and 2; Exelon Generation Company, LLC.” Federal 

8 Register 78(142):44603-44606. July 24, 2013. 

9 78 FR 47800. U.S. Nuclear Regulatory Commission. “License Renewal Application for Byron 

10 Station, Units 1 and 2; Exelon Generation Company, LLC.” Federal 

11 Register 78(151):47800-47802. August 6, 2013.

12 [AEA] Atomic Energy Act of 1954, as amended. 42 U.S.C. § 2011 et seq.

13 Endangered Species Act of 1973, as amended. 16 U.S.C. § 1531 et seq.

14 [Exelon] Exelon Generation Company, LLC. 2013a. “Applicant’s Environmental Report—

15 Operating License Renewal Stage, Byron Station.” May 31, 2013. 707 p. Agencywide 

16 Documents Access and Management System (ADAMS) No. ML14022A048.

17 [Exelon] Exelon Generation Company, LLC. 2013b. “License Renewal Application, Byron and 

18 Braidwood Stations, Units 1 and 2.” June 3, 2013. 3,749 p. ADAMS No. ML131620554. 

19 [MSA] Magnuson–Stevens Fishery Conservation and Management Act, as amended. 

20 16 U.S.C. § 1801 et seq.

21 [NEPA] National Environmental Policy Act of 1969, as amended. 42 U.S.C. § 4321 et seq.

22 [NHPA] National Historic Preservation Act of 1966, as amended. 16 U.S.C. § 470 et seq.

23 [NRC] U.S. Nuclear Regulatory Commission. 1996. Generic Environmental Impact Statement

24 for License Renewal of Nuclear Plants, Final Report. Washington, DC: NRC. NUREG–1437, 

25 Volumes 1 and 2. May 31, 1996. 1,204 p. ADAMS Nos. ML040690705 and ML040690738.

26 [NRC] U.S. Nuclear Regulatory Commission. 1999. Section 6.3—Transportation, Table 9.1, 

27 Summary of findings on NEPA issues for license renewal of nuclear power plants. In: Generic 

28 Environmental Impact Statement for License Renewal of Nuclear Plants. Washington, DC: 

29 NRC. NUREG–1437, Volume 1, Addendum 1. August 1999. ADAMS No. ML040690720.

30 [NRC] U.S. Nuclear Regulatory Commission. 2011. Commission Memorandum and Order: 

31 Denying Suspension Petitions, Addressing Additional Requests for Relief, and Granting a 

32 Request for a Safety Analysis (CLI-11-05). September 9, 2011. ADAMS No. ML11252A958.

33 [NRC] U.S. Nuclear Regulatory Commission. 2013a. Memorandum from L. James, Senior 

34 Project Manager, to A. Simmons, Acting Chief. Subject: Forthcoming meeting to discuss the 

35 license renewal process and environmental scoping for Exelon Generation Company, LLC

36 (Exelon), Byron Nuclear Station, Units 1 and 2. August 7, 2013. ADAMS No. ML13217A069.

37 [NRC] U.S. Nuclear Regulatory Commission. 2013b. Generic Environmental Impact Statement

38 for License Renewal of Nuclear Plants. Revision 1. Washington, DC: NRC. NUREG-1437 

39 Volumes 1, 2, and 3. June 19, 2013. 1,535 p. ADAMS No. ML13107A023. 
Introduction

1-9 

1 [NRC] U.S. Nuclear Regulatory Commission. 2013c Letter from L. James, Project Manager, to 

2 M. Gallagher, Exelon Generating Company, LLC. Subject: “Summary of the site audit related to 

3 the review of the license renewal application for Byron Nuclear Station, Units 1 and 2 (TAC 

4 Nos. MF1834 and MF1835).” October 4, 2013. ADAMS No. ML13270A069.

5 [NRC] U.S. Nuclear Regulatory Commission. 2014. Environmental Impact Statement Scoping 

6 Process Summary Report, Byron Station, Units 1 and 2, Byron, IL. Rockville, MD: NRC. 

7 May 28, 2014. 83 p. ADAMS No. ML14041A334.

2-1 

1 2.0 ALTERNATIVES INCLUDING THE PROPOSED ACTION 

2 Although the U.S. Nuclear Regulatory Commission’s (NRC’s) decisionmaking authority in 

3 license renewal is limited to deciding whether or not to renew a nuclear power plant’s operating 

4 license, the NRC’s implementation of the National Environmental Policy Act (NEPA) requires 

5 consideration of the environmental impacts of potential alternatives to renewing a plant’s 

6 operating license. While the ultimate decision about which alternative (or the proposed action) 

7 to carry out falls to operator, state, or other non-NRC Federal officials, comparing the impacts of 

8 renewing the operating license to the environmental impacts of alternatives allows the NRC to 

9 determine whether the environmental impacts of license renewal are so great that preserving 

10 the option of license renewal for energy-planning decisionmakers would be unreasonable 

11 (10 CFR 51.95(c)(4)). 

12 Energy-planning decisionmakers and owners of the nuclear power plant ultimately decide 

13 whether the plant will continue to operate, and economic and environmental considerations play 

14 important roles in this decision. In general, the NRC’s responsibility is to ensure the safe 

15 operation of nuclear power facilities and not to formulate energy policy or encourage or 

16 discourage the development of alternative power generation. The NRC does not engage in 

17 energy-planning decisions and makes no judgment as to which energy alternatives evaluated 

18 would be the most likely alternative in any given case.

19 The remainder of this chapter provides: (1) a description of the proposed action, (2) a 

20 description of alternatives to the proposed action (including the no-action alternative), and (3) 

21 alternatives to Byron Station, Units 1 and 2 (Byron) license renewal that were considered and 

22 eliminated from detailed study. Chapter 4 of this plant-specific supplemental environmental 

23 impact statement (SEIS) compares the impacts of renewing the operating licenses of Byron and 

24 continued plant operations to the environmental impacts of alternatives.

25 2.1 Proposed Action

26 As stated in Section 1.1 of this document, the NRC’s proposed Federal action is the decision of 

27 whether to renew the Byron operating licenses for an additional 20 years. For the NRC to 

28 determine the impacts from continued operation of Byron, an understanding of that operation is 

29 needed. A description of normal power plant operations during the license renewal term is 

30 provided in Section 2.1.1. Byron is a two-unit, nuclear-powered steam-electric generating 

31 facility that began commercial operation in February 1985 (Unit 1) and January 1987 (Unit 2). 

32 The nuclear reactor for each unit is a Westinghouse pressurized-water reactor (PWR), 

33 producing 2,370 megawatts electric (MWe) (Exelon 2013a). 

34 2.1.1 Plant Operations During the License Renewal Term

35 Most plant operation activities during license renewal would be the same as or similar to those 

36 occurring during the current license term (NRC 2013a). Section 2.1.1 of the Generic 

37 Environmental Impact Statement for License Renewal of Nuclear Power Plants (GEIS), 

38 NUREG-1437, Revision 1 (NRC 2013a), describes the general types of activities that are 

39 carried out during the operation of a nuclear power plant such as Byron, as follows:

40 • reactor operation;

41 • waste management;

42 • security;
Alternatives Including the Proposed Action

2-2 

1 • office and clerical work;

2 • surveillance, monitoring, and maintenance; and

3 • refueling and other outages.

4 As stated in the Exelon Generation Company, LLC’s (Exelon’s) Environmental Report (ER), 

5 Byron will continue to operate during the license renewal term in the same manner as during the 

6 current license term except for, as appropriate, additional aging management programs to 

7 address structure and component aging, in accordance with Title 10 of the Code of Federal 

8 Regulations (10 CFR) Part 54, “Requirements for Renewal of Operating Licenses for Nuclear 

9 Power Plants.” 

10 2.1.2 Refurbishment and Other Activities Associated With License Renewal

11 Refurbishment activities include replacement and repair of major systems, structures, and 

12 components. Replacement activities include replacement of steam generators for PWRs and 

13 recirculation piping systems for boiling-water reactors (BWRs). The major refurbishment class 

14 of activities characterized in the Generic Environmental Impact Statement for License Renewal 

15 of Nuclear Plants (GEIS) (NRC 2013a) is intended to encompass actions that typically take 

16 place only once in the life of a nuclear plant, if at all. Examples of these activities include, but 

17 are not limited to, replacement of boiling-water reactor recirculation piping and pressurized18 water reactor steam generators. These actions may have an impact on the environment 

19 beyond those that occur during normal operations and may require evaluation, depending on 

20 the type of action and the plant-specific design. 

21 In preparation for its license renewal application, Exelon performed an evaluation of these 

22 structures, systems, and components (SSCs) in accordance with 10 CFR 54.21, “Contents of 

23 application—technical information,” to identify the need to undertake any major refurbishment

24 activities that would be necessary to support the continued operation of Byron, during the 

25 proposed 20-year period of extended operation (Exelon 2013a).

26 As a result of its SSC evaluation, Exelon did not identify the need to undertake any major 

27 refurbishment or replacement activities associated with license renewal to support the continued 

28 operation of Byron beyond the end of the existing operating license (Exelon 2013a). Therefore, 

29 refurbishment activities are not discussed under the proposed action in Chapter 4. 

30 However, Exelon identified two hypothetical refurbishment activities that may occur during the 

31 period of continued operation (Exelon 2013a), which will be discussed in Section 4.16, 

32 Cumulative Impacts of Proposed Action:

33  steam generator replacement for Unit 2, and

34  reactor pressure vessel (RPV) head replacement for both or either unit.

35 Exelon’s experience in replacing the steam generators for Unit 1 allowed for a determination 

36 that analyses of environmental impacts associated with the hypothetical steam generator 

37 replacement would bound the hypothetical RPV head replacement. Specifically, the 

38 replacement of the steam generators would require more time (90 days vs. 7 days) and more 

39 people (500 vs. 340) than the RPV head replacement. The remaining factors (personnel 

40 access, parking and potable water supply, sufficient disturbed land to support onsite laydown 

41 facilities, and new storage facility) would be similar for both activities (Exelon 2013a). 

42 As a result of experience and analyses, Exelon chose to analyze the hypothetical replacement 

43 of the Unit 2 steam generators (Exelon 2013a). Specific impacts of the hypothetical 

44 replacement of Unit 2’s steam generators are discussed in Section 4.16, Cumulative Impacts.
Alternatives Including the Proposed Action

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1 2.1.3 Termination of Nuclear Power Plant Operations and Decommissioning After the 

2 License Renewal Term

3 The impacts of decommissioning are described in the Generic Environmental Impact Statement

4 on Decommissioning of Nuclear Facilities: Regarding the Decommissioning of Nuclear Power 

5 Reactors, NUREG-0586 (NRC 2002). The majority of the activities associated with plant 

6 operations would cease with reactor shutdown. Some activities (e.g., security and oversight of 

7 spent nuclear fuel) would remain unchanged, while others (waste management, office and 

8 clerical work, laboratory analysis, and surveillance, monitoring, and maintenance) would 

9 continue at reduced or altered levels. Systems dedicated to reactor operations would cease 

10 operations; however, impacts from their physical presence may continue if not removed after 

11 reactor shutdown. For sites such as Byron, with more than one unit, shared systems may 

12 operate at reduced capacities. Impacts associated with dedicated systems that remain in place 

13 or shared systems that continue to operate at normal capacities would remain unchanged.

14 Decommissioning will occur whether Byron is shut down at the end of its current operating 

15 licenses or at the end of the period of extended operation. There are no site-specific issues 

16 related to decommissioning. The GEIS concludes that license renewal would have a negligible 

17 (SMALL) effect on the impacts of terminating operations and decommissioning on all resources.

18 2.2 Alternatives

19 As stated at the beginning of this chapter, the NRC has the obligation to consider reasonable 

20 alternatives to the proposed action of renewing the license for a nuclear reactor. A reasonable 

21 replacement power alternative must be commercially viable on a scale capable of producing

22 baseload power and must be operational prior to the expiration of the reactor’s operating 

23 license(s), or expected to become commercially viable or expected to produce baseload power 

24 and be operational prior to the expiration of the reactor’s operating license(s). The 2013 GEIS

25 update incorporated the latest information on replacement power alternatives; however, rapidly 

26 evolving technologies are likely to outpace the information presented in the GEIS. As such, a 

27 site-specific analysis of alternatives must be performed for each SEIS, taking into account 

28 changes in technology and science since the preparation of the GEIS.

29 Section 2.2.1 below describes the no-action alternative (i.e., the NRC takes no action and does 

30 not issue renewed licenses for Byron). Sections 2.2.2.1–2.2.2.5 describe the characteristics of 

31 replacement power alternatives for Byron.

32 2.2.1 No-Action Alternative

33 At some point, operating nuclear power plants will terminate operations and undergo 

34 decommissioning. The no-action alternative represents a decision by the NRC not to renew the 

35 operating license of a nuclear power plant beyond the current operating license term. Under the 

36 no-action alternative, the NRC does not renew the operating licenses, and the Byron plant shuts 

37 down at or before the end of the current licenses, in 2024 and 2026. After shutdown, plant 

38 operators will initiate decommissioning in accordance with 10 CFR 50.82.

39 Only those impacts that arise directly as a result of plant shutdown will be addressed in this 

40 SEIS. The environmental impacts from decommissioning and related activities are addressed in 

41 several other documents, including the Final Generic Environmental Impact Statement on 

42 Decommissioning of Nuclear Facilities, NUREG-0586, Supplement 1 (NRC 2002); the license 

43 renewal GEIS, Chapter 4 (NRC 2013a); and Chapter 4 of this SEIS. These analyses either 

44 directly address or bound the environmental impacts of decommissioning whenever Exelon 

45 ceases to operate Byron.
Alternatives Including the Proposed Action

2-4 

1 Even with renewed operating licenses, Byron will eventually shut down, and the 

2 environmental impacts addressed later in Chapter 4 of this SEIS will occur at that time. 

3 As with decommissioning impacts, shutdown impacts are expected to be similar whether they 

4 occur at the end of the current license or at the end of a renewed license. 

5 Termination of operations at Byron would result in the total cessation of electrical power 

6 production. Unlike the alternatives described below in Section 2.2.2, no-action does not 

7 expressly meet the purpose and need of the proposed action as described in Section 1.2, as it 

8 does not provide a means of delivering baseload power to meet future electric system needs. 

9 Assuming that a need currently exists for the power generated by Byron, the no-action 

10 alternative would likely create a need for a replacement power alternative. A full range of 

11 replacement power alternatives (including fossil fuels, new nuclear, and renewable energy 

12 sources) are described in the following section, and their potential impacts are assessed in 

13 Chapter 4. Although the NRC’s authority only extends to the decision of whether to renew the 

14 Byron operating licenses, the replacement power alternatives described in the following sections 

15 represent possible options for energy-planning decisionmakers should the NRC choose not to 

16 renew the Byron operating licenses.

17 2.2.2 Replacement Power Alternatives

18 In evaluating alternatives to license renewal, the NRC considered energy technologies or 

19 options currently in commercial operation, as well as technologies not currently in commercial 

20 operation but likely to be commercially available by the time the current Byron operating 

21 licenses expire. The current operating licenses for the Byron Units 1 and 2 expire on 

22 October 31, 2024, and November 6, 2026, respectively. Alternatives that cannot be 

23 constructed, permitted, and connected to the grid by the time Byron licenses expire were 

24 eliminated from detailed consideration.

25 Alternatives that cannot provide the equivalent of Byron’s current generating capacity and, in 

26 some cases, those alternatives whose costs or benefits do not justify inclusion in the range of 

27 reasonable alternatives, were eliminated from detailed consideration. Each alternative 

28 eliminated from detailed study is briefly discussed, and a basis for its removal is provided at the 

29 end of this section. In total, 17 alternatives to the proposed action were considered (see text 

30 box) and then narrowed to the 5 alternatives considered in Sections 2.2.2.1–2.2.2.5. The NRC 

31 staff evaluated the environmental impacts of these five alternatives and the no-action alternative

32 and discusses them in depth in Chapter 4 of this SEIS. 

33 The GEIS presents an overview of some energy technologies but does not reach any 

34 conclusions about which alternatives are most appropriate. Because many energy technologies 

35 are continually evolving in capability and cost, and because regulatory structures have changed 

36 to either promote or impede development of particular alternatives, the analyses in this chapter 

37 may include updated information from the following sources:

38  Energy Information Administration (EIA),

39  other offices within the U.S. Department of Energy (DOE),

40  U.S. Environmental Protection Agency (EPA),

41  industry sources and publications, and

42  information submitted by Exelon in its ER.
Alternatives Including the Proposed Action

2-5 

1 The evaluation of each alternative in Chapter 4 

2 of this SEIS considers the environmental 

3 impacts across several impact categories: 

4 land use and visual resources, air quality and 

5 noise, geologic environment, water resources, 

6 ecological resources, historic and cultural 

7 resources, socioeconomics, human health, 

8 environmental justice, and waste 

9 management. Most site-specific issues 

10 (Category 2) have been assigned a 

11 significance level of SMALL, MODERATE, or 

12 LARGE. For ecological and historic and 

13 archaeological resources, the impact 

14 significance determination language is specific 

15 to the authorizing legislation (e.g., Endangered 

16 Species Act and National Historic Preservation 

17 Act). The order of presentation of the 

18 alternatives is not meant to imply increasing or 

19 decreasing level of impact. Nor does it imply 

20 that an energy-planning decisionmaker would 

21 be more likely to select any given alternative.

22 To ensure that the alternatives analysis is 

23 consistent with state or regional energy 

24 policies, the NRC reviewed energy-related statutes, regulations, and policies within the Byron 

25 region. As a result, the staff considers alternatives that include wind power or solar photovoltaic 

26 (PV) power, as well as a combination that includes both of them.

27 Region of Influence

28 Byron is owned and operated by Exelon and provides electricity through Commonwealth Edison 

29 (ComEd) (Exelon 2013a). ComEd operates under the PJM Interconnection, a regional 

30 transmission organization that coordinates the movement of wholesale electricity in 13 states 

31 across the Midwest and Northeast (Exelon 2013a). ComEd provides service to 3.8 million 

32 customers across northern Illinois. Its service territory borders Iroquois County to the south, the 

33 Wisconsin border to the north, the Iowa border to the west, and the Indiana border to the east 

34 (ComEd 2013). However, electricity consumption in Illinois is not limited to electricity that is 

35 generated within the State. Although northern Illinois relies on electricity from ComEd, the rest 

36 of Illinois and surrounding states, which are not part of the PJM Interconnection, are part of the 

37 Midcontinent Independent System Operator (MISO) (See Figure 2–1) (Exelon 2013a). 

38 If renewed licenses were not issued, replacement power for Byron would be required in northern 

39 Illinois. Electricity could be replaced by generation sources from a variety of locations. 

40 Electricity could be transported from within the PJM Interconnection; however, the PJM 

41 Interconnection in Illinois is geographically distant from the rest of the PJM region (see 

42 Figure 2–1). It is also possible that electricity within MISO could be purchased by PJM, and 

43 efforts are currently being made to increase coordination and deliverability between the regional 

44 transmission organizations (Ott 2013b). In addition, the State of Illinois has a renewable 

45 portfolio standard that includes a geographic eligibility requirement stipulating that eligible 

46 renewable resources must be procured from facilities located in Illinois or states that adjoin 

47 Illinois (Wisconsin, Indiana, Iowa, Kentucky, Michigan, and Missouri) (ILGA 2011). Renewable 

48 resources can be obtained only from other regions of the country if they are not available in 

49 Illinois or in adjoining states (ILGA 2011). 

Alternatives Evaluated in Depth:

• new nuclear

• coal-integrated gasification combined cycle

• natural gas combined cycle

• combination alternative (wind power, natural gas 

combined cycle, and solar power)

• purchased power

Other Alternatives Considered:

• energy efficiency and conservation

• wind power

• solar power

• hydroelectric power

• wave and ocean energy

• geothermal power

• municipal solid waste

• biomass

• oil-fired power

• fuel cells

• delayed retirement
Alternatives Including the Proposed Action

2-6 

1 Therefore, because replacement power would be required in northern Illinois and any renewable 

2 energy resources would need to be procured from adjoining states, the NRC staff evaluated the 

3 impacts of locating replacement power facilities within the States of Illinois, Indiana, Iowa, 

4 Kentucky, Michigan, Missouri, and Wisconsin. These seven states constitute the region of 

5 influence (ROI) for the NRC staff’s analysis of alternatives. The NRC assumes that 

6 replacement power would either be produced in northern Illinois within the PJM region or would 

7 be purchased by PJM from MISO. 

8 In 2012, electric generators in the ROI had a net summer generating capacity of approximately 

9 179,000 megawatts (MW). This capacity included units fueled by coal (49 percent), natural gas 

10 (27 percent), nuclear (11 percent), and wind (6.6 percent) (EIA 2014c). 

11 In 2011, the electric industry in the ROI provided approximately 744 million megawatt hours 

12 (MWh) of electricity. Electricity produced in the ROI was dominated by coal (67 percent) and 

13 nuclear (21 percent). While natural gas makes up nearly 30 percent of the installed generating 

14 capacity in the ROI, it provides only 6 percent of electricity in the region. Nonhydroelectric 

15 renewable energy produced 1.3 percent of the electricity in the ROI (EIA 2014b).

16 Figure 2–1. Territories of MISO and PJM Interconnection

17

18 Source: MISO-PJM undated

19 Renewable energy legislation in the Region of Influence

20 Renewable energy legislation in Illinois allows the purchase of electricity generation in adjoining 

21 states; therefore, any legislation targeting renewable energy in these states could impact a 

22 state’s incentive to develop renewable resources. Five States in the ROI (Illinois, Iowa, 

23 Missouri, Wisconsin, and Michigan) have legally mandated renewable energy legislation. The 

24 State of Indiana has a voluntary program, and State of Kentucky does not have any renewable 

25 energy requirements. The paragraphs below briefly outline each state’s program, including 

26 renewable energy goals and benchmarks. 

27 In August 2007, Illinois adopted a renewable portfolio standard that requires the State’s utilities 

28 to produce at least 25 percent of their power from renewable sources by 2025, 75 percent of 

29 which must come from wind. Solar photovoltaics must comprise 6 percent of the annual 

30 requirement for calendar year 2015 and thereafter. Other eligible sources include biomass and 
Alternatives Including the Proposed Action

2-7 

1 existing hydroelectric power (DSIRE 2012a). The law also includes an energy efficiency 

2 standard that requires utilities to implement cost-effective energy efficiency measures to meet 

3 energy savings of 2 percent by calendar year 2015 and thereafter (ILGA 2011). For electric 

4 utilities (including ComEd), eligible resources must be located in Illinois; resources can be 

5 purchased from adjoining states only if there are insufficient instate resources (ILGA 2011).

6 Iowa’s Alternative Energy Production Law requires the State’s two investor-owned utilities to 

7 generate a combined total of 105 megawatts (MW) of their generating capacity from renewable 

8 energy sources. A 2007 order allows the utilities to participate in renewable energy credit 

9 trading programs by distinguishing between renewable electricity production capacity used to 

10 comply with Iowa law and that which can be used to satisfy other states’ renewable portfolio 

11 standards (DSIRE 2012b).

12 Missouri adopted a renewable portfolio standard that requires investor-owned utilities to 

13 increase their use of renewable sources by 15 percent by 2021 and includes a provision 

14 specifying that 2 percent of the renewable portfolio standard requirement must be met by solar 

15 energy. Resources can be purchased from outside Missouri, but renewable energy generated 

16 in State receives a multiplier of 1.25 compared to out-of-State generation (DSIRE 2013b).

17 Wisconsin’s renewable portfolio standard requires utilities to produce 10 percent of their 

18 electricity from renewable sources by 2015. Included in the renewable portfolio standard is a 

19 provision that allows electricity providers to create and sell or transfer renewable resource 

20 credits and renewable energy certificates. Renewable energy generated outside Wisconsin is 

21 eligible, provided that the electricity is distributed to Wisconsin customers (DSIRE 2012c). 

22 Michigan enacted a Renewable Energy Standard in 2008 that requires utilities to generate 

23 10 percent of their retail electricity sales from renewable energy resources by 2015. The 

24 standard also allows energy efficiency and advanced cleaner energy systems to meet part of 

25 the requirement. Renewable energy credits can be purchased from in-State or out-of-State 

26 facilities, provided that the facilities are located within the retail electric service territory of a 

27 utility that is recognized by the Michigan Public Service Commission (DSIRE 2013a). 

28 Indiana does not have a mandatory renewable or alternative energy portfolio standard. On 

29 July 9, 2012, Indiana adopted a Clean Energy Portfolio Standard, which sets a voluntary goal of 

30 10 percent clean energy by 2025, based on the amount of electricity supplied by the utility in 

31 2010. Unlike many of the other ROI states, up to 30 percent of the goal may be met with clean 

32 coal technology, nuclear energy, combined heat and power systems, natural gas that displaces 

33 electricity from coal, clean coal technology, and net-metered distributed generation facilities. 

34 Fifty percent of qualifying energy must come from within the State (DSIRE 2012d). 

35 Kentucky is the only state in the ROI that does not have mandatory or voluntary renewable 

36 energy requirements.

37 Given known technology and technological and demographic trends, the EIA predicts that 

38 32 percent of electricity in the United States will be generated by coal in 2040 (EIA 2013a). In 

39 all the Midwest case projections, coal accounts for 42 percent in 2040 (EIA 2013a). Natural gas 

40 generation rose from 16 percent in 2000 to 24 percent in 2011 and is projected to increase to 

41 35 percent in 2040, surpassing coal as the largest share of U.S. electric power generation 

42 (EIA 2013a, 2013d). Electricity generation from renewable energy is expected to grow from 

43 13 percent of total generation in 2011 to 16 percent in 2040. However, there are uncertainties 

44 that could affect this forecast, particularly the implementation of policies aimed at reducing 

45 greenhouse gas emissions which would have a direct effect on fossil fuel based generation 

46 technologies (EIA 2013a).
Alternatives Including the Proposed Action

2-8 

1 This section describes replacement power alternatives to license renewal. These include a new 

2 nuclear alternative in Section 2.2.2.1; a coal-integrated gasification combined cycle (IGCC) 

3 alternative in Section 2.2.2.2; a natural gas combined-cycle (NGCC) alternative in 

4 Section 2.2.2.3; a combination natural gas, wind, and solar power alternative in Section 2.2.2.4; 

5 and a purchased power alternative in Section 2.2.2.5. Table 2–1 summarizes key design 

6 characteristics of the alternative technologies evaluated in depth. The environmental impacts of 

7 these alternatives are evaluated in Chapter 4. 
Alternatives Including the Proposed Action

2-9 

1 Table 2–1. Summary of Replacement Power Alternatives and Key Characteristics 

2 Considered in Depth

New Nuclear 

Alternative IGCC Alternative NGCC Alternative Combination Alternative

Summary of 

Alternative

Two-unit nuclear 

plant, each with 1,120 

MWe, for a total of 

2,240 MWe

Four 618-MWe units, 

for a total of 

2,472 MWe

Five 560-MWe 

units, for a total of 

2,800 MWe

One 360 MWe 

NGCC unit; a 1,813 

MWe wind farm; 

and a 227 MWe 

installed solar 

photovoltaic facility, 

for a total of 2,400 

MWe.

Location

An existing nuclear 

plant site or retired 

coal plant site. New 

transmission line(s) 

and other 

infrastructure 

upgrades may be 

required. Some 

facilities (e.g., support 

buildings, potable 

water supply, and 

sanitary discharge

structures) could be 

shared with existing 

plant.

An existing plant site 

or retired coal plant 

site. New 

transmission line(s) 

and other 

infrastructure 

upgrades may be 

required. Some 

facilities (e.g., support 

buildings, potable 

water supply, and 

sanitary discharge

structures) could be 

shared with existing 

plant.

An existing plant 

site or retired coal 

plant site. New 

transmission line(s) 

and other 

infrastructure 

upgrades may be 

required; would 

require construction 

of a new or 

upgraded pipeline. 

Some facilities 

(e.g., support 

buildings, potable 

water supply, and 

sanitary discharge

structures) could be 

shared with existing 

plant.

Spread across 

multiple sites 

throughout the ROI

Cooling 

System

Closed-cycle with 

natural draft cooling 

towers. Cooling 

water withdrawal—54 

mgd; consumptive 

water use—40 mgd 

(NRC 2008).

Closed-cycle with 

mechanical draft 

cooling towers. 

Cooling water 

withdrawal—25 mgd; 

consumptive water 

use—20 mpd 

(NETL 2013a).

Closed-cycle with 

mechanical draft 

cooling towers. 

Cooling water 

withdrawal—17 

mgd; consumptive 

water use—13 mgd 

(NETL 2013a).

For NGCC portion, 

closed-cycle with 

mechanical draft 

cooling towers. 

Cooling water 

would be 15% of 

that required for 

NGCC alternative. 

Minimal water use 

for wind and solar.
Alternatives Including the Proposed Action

2-10

New Nuclear 

Alternative IGCC Alternative NGCC Alternative Combination Alternative

Land 

Requirements

355 ac (144 ha) 

(NRC 2008); 520 ac 

(210 ha) for uranium

mining and 

processing 1

(NRC 2013a)

2,000 ac (800 ha) for 

the major permanent

facilities; 1,100 ac 

(450 ha) per year for 

mining (DOE 2010a)

94 ac (38 ha) for the 

plant, including 

pipelines 

(Exelon 2013a); 

10,080 ac 

(4,079 ha) for gas 

extraction and 

collection 

(NRC 1996)

Wind farms would 

require 3,376 ac 

(1,366 ha) to 

10,127 ac 

(4,098 ha); (WAPA 

and FWS 2013); 

solar photovoltaic 

facilities would 

require 6,749 ac 

(2,731 ha) (Ong 

et al. 2013). For 

NGCC portion, land 

use would remain 

the same at 94 ac 

(38 ha) 

(Exelon 2013a).

Work Force

3,500 workers during 

peak construction; 

812 workers during 

operations 

(NRC 2008)

4,600 workers during 

peak construction; 

420 workers during 

operations 

(DOE 2010a)

1,783 workers 

during peak 

construction; 94 

workers during 

operations 

(Exelon 2013a)

Solar photovoltaic—

600 workers during 

peak construction, 

60 workers during 

operations; for 

wind—931 workers 

during construction, 

566 workers during 

operations 

(DOE 2010b). The 

number of 

construction and 

operations workers 

would be less than 

the standalone 

alternative but 

would not be a 

linear reduction 

because of needing 

a minimum number 

of workers 

regardless of the 

size of the NGCC 

plant. 

1 Normalized to model light water reactor annual fuel requirement. 46% of this land requirement is temporarily 

committed land.

Key: ac = acres; cfs = cubic feet per second; ha = hectares; IGCC = coal-integrated gasification combined cycle; 

mgd = million gallons per day; MWe = megawatts electric; NGCC = natural gas combined-cycle; ROI = region of 

influence

Sources: DOE 2010a, 2010b; Exelon 2013a; NETL2013a; NRC 1996, 2008, 2013b; Ong et al. 2013; WAPA and 

FWS 2013
Alternatives Including the Proposed Action

2-11

1 2.2.2.1 New Nuclear Alternative

2 In this section, NRC staff describes the new nuclear alternative. NRC staff evaluates the 

3 environmental impacts from this alternative in Chapter 4. 

4 The NRC staff considered the construction of a new nuclear plant to be a reasonable alternative 

5 to license renewal. For example, nuclear generation currently provides 21 percent of electricity 

6 generation in the ROI (EIA 2014b). Twelve nuclear power plants operate in the ROI; 

7 six applicants have received renewed licenses and three additional applicants have applied for 

8 renewed licenses from the NRC (including Byron) (NRC 2013b). In addition, there is interest in 

9 new nuclear power plant development in the region; combined license (COL) applications have 

10 been filed for two new nuclear power plants in the ROI. On July 24, 2008, Union Electric 

11 Company submitted a COL application for Callaway Plant, Unit 2 (Callaway Unit 2), in Callaway 

12 County, Missouri, on the existing Callaway site (AmerenUE 2009). However, that application 

13 has since been suspended (NRC 2009b). An application was also filed in September 2008 for 

14 Enrico Fermi Atomic Power Plant, Unit 3 (Fermi Unit 3), in Monroe County, Michigan, on the 

15 existing Fermi site. The NRC staff published the Final Environmental Impact Statement (EIS) 

16 for Fermi 3 in January 2013 (NRC 2013c). Although the State of Indiana does not currently 

17 have any nuclear power plants, its voluntary clean energy initiative includes nuclear as an

18 eligible technology (DSIRE 2012b).

19 The NRC staff determined that there is sufficient time for Exelon to prepare and submit an 

20 application, build, and operate two new nuclear units before the Byron licenses expire in 

21 October 2024 and November 2026. For example, the NRC staff review of a COL application 

22 that references a certified design is at least 30 months, not including hearing time. Noncertified 

23 designs would take 48 to 60 months to review (NRC 2009a). The recently licensed Vogtle 

24 Electric Generating Plant, Units 3 and 4 (Vogtle Units 3 and 4), anticipates a construction 

25 schedule of 6 to 7 years (Southern 2013). 

26 In evaluating the new nuclear alternative, the NRC staff assumed that two new nuclear reactors 

27 would be built on an existing nuclear or coal power plant site, allowing for the maximum use of 

28 existing ancillary facilities such as support buildings and transmission infrastructure. In 1987, 

29 Illinois passed a moratorium preventing the construction of new nuclear power plants within the 

30 state. Unless the moratorium is lifted, any new nuclear alternative would have to be located 

31 elsewhere in the ROI. For the purposes of this analysis, the NRC relied on the Vogtle Units 3 

32 and 4 COL EIS for technological parameters for the new nuclear alternative, because the Vogtle 

33 Units 3 and 4 COL considers two new nuclear reactor units with similar output as Byron and is 

34 representative of the reactors that could be constructed in the ROI before Byron’s licenses 

35 expire (NRC 2011). As such, the NRC staff assumed two Westinghouse AP1000 reactors with 

36 a net electrical output of 2,240 MWe would replace Byron’s current reactors for this alternative. 

37 The NRC staff estimated that 324 acres (ac) (131 hectares (ha)) of additional land would be 

38 required on a long-term basis because of permanent facilities, and an additional 31 ac (12.5 ha) 

39 would be disturbed for temporary facilities, a laydown area, and storage of dredge material 

40 (NRC 2008). 

41 The heat rejection demands of a new nuclear alternative would be similar to those of Byron. 

42 The new reactors may require a new cooling system (including natural draft cooling towers and 

43 intake and discharge structures). The NRC staff assumes that water requirements for the new 

44 nuclear alternative would be similar to current water use at Byron. The existing transmission 

45 lines leaving the site, as well as construction and drinking water wells are expected to serve the 

46 replacement reactor with few modifications required. A new onsite transmission line may be 

47 required if insufficient transmission occurs on the site. Construction materials would be 

48 delivered by a combination of rail spur, truck, and barge, depending on the specific site location. 
Alternatives Including the Proposed Action

2-12

1 It is possible that modifications would be required to deliver such materials, depending on the 

2 existing infrastructure at the site; modifications could include new rail lines or access roads.

3 The NRC staff also considered the installation of multiple small modular reactors as an 

4 alternative to renewing the Byron licenses. The NRC established the Advanced Reactor 

5 Program in the Office of New Reactors because of considerable interest in small modular 

6 reactors along with anticipated license applications by vendors. Small modular reactors are 

7 approximately 300 megawatts (MW) or less, would have lower initial capacity than large-scale 

8 units, and would have siting flexibility for locations that are not large enough to accommodate 

9 traditional nuclear reactors (DOE undated b). As of January 2014, no applications for small 

10 modular reactors have been submitted to the NRC. The DOE has estimated that the technology 

11 may achieve commercial operation by 2021 to 2025 (DOE undated b). Because small modular 

12 reactors are not expected to be operational at a commercial scale until near the time Byron’s 

13 licenses expire, it is unlikely that eight new small modular reactors (the number of units required 

14 to replace Byron’s current output) could be constructed in the ROI; therefore, this analysis 

15 focuses on nuclear generation by larger nuclear units.

16 2.2.2.2 IGCC Alternative

17 In this section, the NRC staff describes the IGCC alternative. The NRC staff evaluates the 

18 environmental impacts from this alternative in Chapter 4. 

19 Coal provides the greatest share of electrical power in the ROI, and in 2010, coal represented 

20 49 percent of installed generation capacity and accounted for 67 percent of all electricity 

21 generated in the ROI (EIA 2014b). IGCC is a technology that generates electricity from coal 

22 and combines modern coal gasification technology with both gas-turbine and steam-turbine 

23 power generation. The technology is cleaner than conventional pulverized coal plants because 

24 major pollutants are removed from the gas stream before combustion. An IGCC power plant 

25 consists of coal gasification and combined-cycle power generation. Coal gasifiers convert coal 

26 into a gas (synthesis gas, also referred to as syngas) which fuels the combined-cycle power 

27 generating units. The combined-cycle system for a 618-MWe IGCC power plant includes two 

28 combustion turbines, two heat recovery steam generators, and a steam turbine. The combined29 cycle units combust gas in one or more combustion turbines, and the resulting hot exhaust gas 

30 is then used to heat water into steam to drive a steam turbine. The steam turbine then uses the 

31 heat from the gas turbine’s exhaust through a heat recovery steam generator to produce 

32 additional electricity (DOE 2010a). This two-cycle process has a high rate of efficiency, since 

33 the exhaust heat that would otherwise be lost is captured and reused. In addition, the power 

34 plant would reduce sulfur dioxide, nitrogen oxides, mercury, and particulate emissions by 

35 removing constituents from the syngas before combustion. Nearly 100 percent of the nitrogen 

36 from the syngas would be removed prior to combustion in the gas turbines and would result in 

37 lower nitrogen oxide emissions compared to conventional coal-fired power plants (DOE 2010a). 

38 IGCC power plants have been in operation since the mid-1990s; the Wabash Rice IGCC 

39 repowering project in Indiana and the Polk Power Station in Florida are two examples of 

40 operating IGCC plants. Recently, there has been an increased interest in new IGCC projects, 

41 and multiple new projects have been proposed or have recently begun operations in the 

42 United States. The Duke Energy Edwardsport Generation Station in Indiana is a 618-MWe 

43 IGCC power plant in the ROI that began commercial operation in June 2013. Duke Energy 

44 estimates that the IGCC plant will produce 10 times as much power as the retired coal plant it 

45 replaced with 70 percent fewer emissions of sulfur dioxide, nitrogen oxides, and particulates. 

46 The IGCC plant will reduce carbon emissions per MWh by nearly half (Duke Energy 2013). In 

47 addition, the Edwardsport Generation Station has potential for carbon capture and geologic 
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1 sequestration. Space has been reserved at the site for carbon dioxide capture equipment 

2 (NETL 2013b). 

3 Many IGCC power plants have been designed with carbon capture and storage (CCS) to further 

4 reduce carbon dioxide emissions. The Kemper County IGCC project in east-central Mississippi 

5 proposes to use CCS to reduce carbon dioxide emissions by almost 70 percent by removing 

6 carbon from the syngas post-gasification (DOE 2010a). According to a 2013 National Energy 

7 Technology Laboratory (NETL) report, nine IGCC projects totaling over 4,000 MW are currently 

8 active; these projects are in the planning stages, or they have begun construction. 

9 Thirteen projects have been proposed and subsequently cancelled for a variety of reasons, 

10 including air quality issues, state laws and regulations, redirected focus on gas-fired generation 

11 and renewables, and unanticipated rising costs (NETL 2013c). 

12 IGCC technology and proposed projects have experienced a number of setbacks and 

13 opposition, hindering IGCC’s ability to fully integrate into the energy market. The most 

14 significant roadblock is IGCC’s high capital cost compared to conventional coal-fired power 

15 plants. Cost overruns have been experienced at both the Edwardsport IGCC project and the 

16 Kemper County IGCC project. FutureGen, an IGCC plant featuring CCS, lost DOE financial 

17 support because of escalating cost estimates (Reuters 2012). Other issues include:

18  construction timeline overruns,

19  limited track record for reliable performance, and

20  opposition from an environmental perspective (Rosenberg 2004).

21 Despite some of the current setbacks and concerns associated with IGCC projects, the NRC 

22 staff considers IGCC technology to be a reasonable source of baseload power to replace Byron 

23 by the time its licenses expire in 2024 and 2026 because of the current regulatory framework 

24 and the number of active IGCC plants within the ROI. For example, on January 8, 2014, EPA

25 issued a proposed rule for carbon pollution that would apply to new fossil fuel-fired power 

26 plants. The action proposes performance standards for utility boilers and IGCC units based on 

27 partial implementation of a CCS system as the best method of emission reduction. The 

28 proposed emission limit for these sources is 1,100 lb carbon dioxide per megawatt hour 

29 (CO2/MWh). The proposed rule cites a number of IGCC projects and concludes that the 

30 projects are “consistent with the EIA modeling which projects that few, if any, new coal-fired 

31 units would be built in this decade and that those that are built would include CCS” 

32 (79 FR 1430). If this rule becomes final, any new coal-fired power plants would likely require 

33 CCS in order to achieve the 1,100 lb CO2/MWh emission limit. Therefore, in this section, the 

34 NRC staff considers IGCC power plants as an alternative to Byron because the Edwardsport 

35 IGCC project in Indiana is currently in operation and the Kemper IGCC project in Mississippi is 

36 under construction. The technology parameters for these plants are considered the current 

37 state of technology and are used here to describe a hypothetical IGCC power plant located on 

38 an existing power plant site within the ROI. 

39 To replace the electricity that Byron generates, the NRC staff considered four IGCC units, each 

40 with a net capacity of 618 MWe. Various coal sources are available to coal-fired power plants in 

41 the ROI. For the purpose of this evaluation, the NRC staff assumes that the IGCC alternative 

42 would burn a sub-bituminous coal, based on the type of coal used in electric plants in Illinois. 

43 NRC staff presumes that coal burned in Illinois will be representative of coal that would be 

44 burned in an IGCC alternative regardless of where it may be located (EIA 2012). The IGCC 

45 units would reduce sulfur dioxide, nitrogen oxides, mercury, and particulate emissions by 

46 removing constituents from the syngas. The removal of nearly 100 percent of the nitrogen from 

47 the syngas prior to combustion in the gas turbines would result in significantly lower nitrogen 
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1 oxide emissions compared to conventional coal-fired fired power plants (DOE 2010a). In 

2 addition, the units would be designed with the potential to add CCS later. In a CCS, carbon 

3 dioxide emissions would be compressed and piped off site where it could be sold for beneficial 

4 use or geologic storage. Additional discussion of air quality impacts associated with the IGCC 

5 alternative is discussed in Section 4.3.

6 The IGCC alternative would be located at an existing site (such as an existing power plant site) 

7 to maximize availability of infrastructure and reduce other environmental impacts. Depending 

8 on the specific site location, there might be a need to construct new intake and discharge

9 facilities and a new cooling system. The IGCC alternative would use about the same amount of 

10 water as Byron and a similar amount as the Edwardsport IGCC plant. The NRC staff assumes 

11 the cooling system would use a closed-cycle system with mechanical draft cooling towers. This 

12 system would withdraw 25 million gallons per day (gpd) (95 million liters per day (Lpd)) of water 

13 and consume 20 million gpd (76 million Lpd). Onsite visible structures could include the boilers, 

14 exhaust stacks, intake and discharge structures, mechanical draft cooling towers, transmission 

15 lines, and an electrical switchyard. Construction materials would be delivered by a combination 

16 of rail spur, truck, and barge, depending on the specific site location. Modifications may be 

17 required to deliver such materials; modifications could include new rail lines or access roads.

18 The NRC staff also considered supercritical pulverized coal (SCPC) as an alternative to 

19 renewing the Byron licenses. SCPC was dismissed as the coal alternative because of new 

20 regulations aimed at limiting the environmental impacts from conventional pulverized coal 

21 plants. The presence of active IGCC plants in the ROI also contributed to the selection of IGCC 

22 for analysis. 

23 2.2.2.3 NGCC Alternative

24 In this section, the NRC staff describes the NGCC alternative. The NRC staff evaluates the 

25 environmental impacts from this alternative in Chapter 4. 

26 Natural gas represents nearly 30 percent of installed generation capacity in the ROI, but 

27 provides only 6 percent of all electrical power in the ROI (EIA 2014b and 2014c). Nationwide, 

28 the percentage of power generated by natural gas is expected to rise by 2040, although the 

29 actual rise in natural gas generation will depend on future natural gas prices (EIA 2013a). The 

30 NRC staff considers the construction of an NGCC power plant to be a reasonable alternative to 

31 license renewal because it is a feasible, commercially available option for providing electrical 

32 generating capacity beyond the expiration of Byron’s current licenses. 

33 Baseload NGCC power plants have proven their reliability and can have capacity factors as high 

34 as 85 percent. In an NGCC system, electricity is generated using a gas turbine that burns 

35 natural gas. A steam turbine uses the heat from gas turbine exhaust through a heat recovery 

36 steam generator to produce additional electricity. This two-cycle process has a high rate of 

37 efficiency since the exhaust heat that would otherwise be lost is captured and reused. Like 

38 other fossil fuel sources, NGCC power plants are a source of greenhouse gases, including 

39 carbon dioxide. An NGCC power plant, however, produces significantly fewer greenhouse 

40 gases per unit of electrical output than conventional coal-powered plants. 

41 To replace the electricity that Byron generates, the NRC staff considered five NGCC units, each 

42 with a net capacity of 560 MWe (NETL 2007). The NRC staff assumes that each plant 

43 configuration consists of two combustion turbine generators, two heat recovery steam 

44 generators, and one steam turbine generator with mechanical draft cooling towers for heat 

45 rejection. The power plant is assumed to incorporate a selective catalytic reduction (SCR) 

46 system to minimize the plant’s nitrogen oxide emissions (NETL 2007).
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This 2,800-MWe NGCC plant would consume 124 billion cubic feet (ft3 1 ) (3,500 million cubic 

meters (m3 2 )) of natural gas annually, assuming an average heat content of 1,021 British thermal 

units per cubic foot (BTU/ft3 3 ) (EIA 2013c). Natural gas would be extracted from the ground 

4 through wells, then treated to remove impurities and blended to meet pipeline gas standards 

5 before being piped through the State pipeline system to the plant site. This NGCC alternative 

6 would produce relatively little waste, primarily in the form of spent catalysts used for control of 

7 nitrogen oxide emissions.

8 The NGCC alternative would be located at an existing power plant site to maximize availability 

9 of infrastructure and reduce other environmental impacts. Depending on the specific site 

10 location, there might be a need to construct new intake and discharge facilities and a new 

11 cooling system. Because NGCC power plants generate much of their power from a gas-turbine 

12 combined-cycle plant, and the overall thermal efficiency of this type of plant is high, an NGCC 

13 alternative would require less cooling water than Byron would. This system would withdraw 

14 17 million gallons per day (gpd) (64 million litres per day (Lpd)) of water and consume 

15 13 million gpd (49 Lpd). The NRC staff assumes the cooling system would use a closed-cycle 

16 system with mechanical draft cooling towers. Onsite visible structures could include the cooling 

17 towers, exhaust stacks, intake and discharge structures, transmission lines, natural gas 

18 pipelines, and an electrical switchyard. Construction materials would be delivered by a 

19 combination of rail spur, truck, and barge, depending on the specific site location. Modifications 

20 may be required to deliver such materials; modifications could include new rail lines or access 

21 roads.

22 2.2.2.4 Combination Alternative (NGCC, Wind, Solar)

23 In this section, NRC staff describes the environmental impacts of a combination alternative to 

24 the continued operation of Byron, consisting of an NGCC facility constructed at an existing 

25 power plant site, operating in conjunction with land-based wind farms as well as solar energy 

26 facilities, all of which would be located within the ROI. The NRC staff evaluates the 

27 environmental impacts from this alternative in Chapter 4. 

28 To serve as an effective baseload power alternative to the Byron reactors, this combination 

29 alternative must be capable of providing an equivalent amount of baseload power. For the 

30 purpose of this evaluation, the NRC staff presumes that NGCC, wind farms, and solar 

31 photovoltaic facilities would comprise the combination alternative. 

32 NGCC Portion of the Combination Alternative

33 To produce its required share of power, the NGCC portion, operating at an expected capacity 

34 factor of 85 percent (NETL 2007), would need to have a nameplate rating of approximately 

35 425 MWe. 

36 In 2013, the EIA reported that natural gas-fired power plants are generally used infrequently for 

37 shorter periods to meet peak demand. Capacity factors for natural gas plants averaged less 

38 than 5 percent during off-peak demand hours for most regions of the country. Natural gas is 

39 used for these “peaker plants” because natural gas combustion turbines can respond quickly, so 

40 they tend to be used to meet short-term increases in electricity demand (EIA 2013d). A report 

41 prepared by CITI Research stated that gas-fired power plants can help overcome the 

42 intermittent nature of renewable energy (Channell et al. 2012). The peaking aspect of natural 

43 gas-fired power plants makes natural gas an ideal addition to an otherwise renewable energy 

44 combination alternative.

45 NRC staff assumed that one new NGCC unit of the type described in Section 2.2.2.3 would be 

46 constructed and installed at an existing power plant site with a total net capacity of 360 MWe. 

47 The appearance of an NGCC unit would be similar to that of the full NGCC alternative 
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1 considered in Section 2.2.2.3, although only one unit would be constructed. The NRC staff 

2 assumes that the NGCC portion of this alternative, which is assumed to be located at an 

3 existing power plant site, would utilize existing electrical switchyards, substations, and 

4 transmission lines. Depending on the existing site conditions, it is possible that intake and 

5 discharge structures of the existing cooling system could continue in service, but would be 

6 connected to a new closed-cycle cooling system. For the purposes of this analysis, the NRC 

7 staff assumes that the NGCC portion of the combination would utilize mechanical draft cooling 

8 towers.

9 Wind Portion of the Combination Alternative

10 The NRC staff assumes that the wind-generated power from this combination alternative would 

11 come from land-based wind farms which would be located in the ROI within the states of Illinois, 

12 Indiana, Iowa, Kentucky, Michigan, Missouri, or Wisconsin. The wind portion, assuming a 

13 capacity factor of 30 percent, would require a nameplate capacity of 6,042 MWe (WAPA and 

14 FWS 2013).

15 The American Wind Energy Association (AWEA) reports a total of more than 60,000 MW of 

16 installed wind energy capacity nationwide as of March 31, 2013 (AWEA 2013). As of 

17 March 2013, Texas is by far the leader in installed land-based capacity with 12,214 MW. 

18 Two states in the ROI have the third- and fourth-largest installed capacity: Iowa with 5,133 MW, 

19 followed by Illinois with 3,568 MW (AWEA 2013). The installed wind capacity in the ROI has 

20 been increasing annually by 1,000 MWe to 2,500 MWe in each of the past 6 years, for a total of 

21 over 11,000 MWe of additional wind capacity from 2007 to 2012 (DOE 2013a). Therefore, NRC 

22 staff considers 6,042 MW of wind energy to be a reasonable amount by the time the Byron 

23 licenses expire in 2024 and 2026. As is the case with other renewable energy sources, the 

24 feasibility of wind resources serving as alternative baseload power is dependent on the location 

25 (relative to expected load centers), value, accessibility, and constancy of the resource. Wind 

26 energy must be converted to electricity at or near the point where it is extracted, and there are 

27 limited energy storage opportunities available to overcome the intermittency and variability of 

28 wind resources. At the current stage of wind energy technology development, wind resources in 

29 wind power class 3 and higher are suitable for most utility scale applications (NREL 2014). 

30 Wind power class 3 is defined as having a wind speed of 15.7 miles per hour (mph) (7.0 meters 

per second (m/s)) and a wind density of 500 watts per square meter (W/m2 31 ) at 164 ft (50 m) 

32 (NREL 2014). Individual wind turbine capacity increased from 0.71 MW in 1999 to 1.79 MW in 

33 2010. The size of turbine most frequently installed in the United States in recent years is the 

34 1.5-MW turbine (WAPA and FWS 2013). For the purposes of this analysis, the NRC staff 

35 assumes wind turbines with a capacity of 1.79 MW. The capacity factors of land-based wind 

36 farms are lower than offshore wind farms (WAPA and FWS 2013). For the wind portion of the 

37 combination alternative, the NRC staff assumed a capacity factor of 30 percent, resulting in an 

38 estimated total net capacity of 1,813 MWe. Wind turbines must be well-separated from each 

39 other to avoid interferences to wind flowing through the wind farm, resulting in wind farms 

40 requiring substantial amounts of land. Wind turbines may require as much as 1 to 3 ac (0.4 to 

41 1.2 ha) of land for each turbine (WAPA and FWS 2013). Based on the size of the turbines and 

42 amount of land required between each turbine, approximately 3,376 turbines and 3,376 to 

43 10,127 ac (1,366 to 4,098 ha) would be required for the wind portion of the combination 

44 alternative.

45 Wind energy’s intermittency affects its viability and value as a baseload power source. 

46 However, the variability of wind-generated electricity can be lessened if the proposed wind 

47 farms were located at a large distance from one another and allowed to operate as 

48 interconnected wind farms, an aggregate controlled from a central point. Distance separation 

49 ensures that the two wind farms will not simultaneously experience the same climate, and 
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1 power will likely be produced at some of the wind farms at any given time (Archer and 

2 Jacobson 2007). 

3 Solar Photovoltaic Portion of the Combination Alternative

4 The solar portion of the combination alternative would be generated through one or more solar 

5 photovoltaic energy facilities located in the ROI. Assuming a capacity factor of 19 percent, the 

6 solar energy facilities would need a collective nameplate rating of 1,193 MWe. Solar 

7 photovoltaic technologies could be installed on building roofs at existing residential, commercial, 

8 or industrial sites or at larger standalone solar facilities. 

9 Nationwide, growth in large solar photovoltaic facilities (greater than 5 MW) has resulted in an 

10 increase from 70 MW in 2009 to over 700 MW installed capacity in 2011. As of January 2012, it 

11 is estimated that more than 11,000 MW of large solar photovoltaic projects have signed power 

12 purchase agreements (Mendelsohn et al. 2012). Over 9,000 MW of those solar projects are 

13 50 MW or greater, although most are located in the southwestern United States (Mendelsohn 

14 et al. 2012). As described in Section 2.2.2, two States in the ROI (Missouri and Illinois) have 

15 renewable energy legislation that includes requirements for solar photovoltaic technology. 

16 Missouri’s renewable portfolio standard includes a provision specifying that 2 percent of the 

17 renewable portfolio standard requirement must be met by solar energy by 2021. Illinois’ 

18 renewable portfolio standard specifies that solar photovoltaic must comprise 6 percent of the 

19 annual requirement for the year 2015-2016 and thereafter. As of 2010, only 9 MW of solar 

20 energy capacity had been installed in the ROI. 

21 Solar photovoltaic resources in the ROI range from 4.0 to 5.0 kilowatt hours per square meter 

per day (kWh/m2 22 /day). The most viable solar resources are located in Missouri, Iowa, and 

23 southern Illinois and Indiana (NREL 2013c). Economically viable solar resources are 

considered to be 6.75 kWh/m2 24 /day and greater (BLM and DOE 2010). As is the case with wind 

25 energy sources, the feasibility of solar energy resources serving as alternative baseload power 

26 is dependent on the location, value, accessibility, and constancy of the resource. Solar 

27 photovoltaic uses solar panels to convert solar radiation into usable electricity. Solar cells are 

28 formed into solar panels by solar manufacturers that can then be linked into photovoltaic arrays 

29 to generate electricity. The electricity generated can be stored, used directly, fed into a large 

30 electricity grid, or combined with other electricity generators as a hybrid plant. Solar 

31 photovoltaics can generate electricity whenever there is sunlight, regardless of whether or not 

32 the sun is directly shining on solar panels. Therefore, solar photovoltaic technologies do not 

33 need to directly face and track the sun, which has allowed solar photovoltaic systems to have 

34 broader geographical use than concentrated solar power (Ardani and Margolis 2011). Because 

35 the ROI contains average solar photovoltaic resources and solar photovoltaics is a commercially 

36 available option for providing electrical generating capacity, the NRC staff considers the 

37 construction of solar photovoltaic facilities to be a reasonable alternative to license renewal 

38 when combined with wind and NGCC.

39 For the purposes of this analysis, the NRC staff assumes solar photovoltaic facilities with a 

40 capacity factor of 19 percent (Ardani and Margolis 2011). Solar photovoltaic facilities may 

41 require 6.2 ac (2.5 ha)/MW of land (NRC 2013a). Although not all of this land would be cleared 

42 of vegetation and permanently impacted, it represents the land enclosed in the total site 

43 boundary of the solar facility (Ong et al. 2013). For the solar portion of this combination 

44 alternative, approximately 7,397 ac (2,993 ha) would be required to support an installed net 

45 capacity of 227 MWe. In this analysis, the NRC staff does not speculate on the number and 

46 size of individual solar facilities, nor their locations within the ROI. However, as stated above, 

47 some of the output could be realized by solar photovoltaic installations on building roofs at 

48 existing residential, commercial, or industrial sites or at larger standalone solar facilities. To the 
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1 extent that rooftop or building-integrated solar photovoltaic installations remain popular, land 

2 impacts would be relatively minor. Solar photovoltaic systems do not require water for cooling 

3 purposes, but a small amount of water is needed to clean the panels and for potable water for 

4 the workforce. Impacts identified in the BLM and DOE’s Solar Energy Programmatic 

5 Environmental Impact Statement (PEIS) (BLM and DOE 2010, 2012), among other technical 

6 reports, provide information used in the analyses presented in the impact sections in Chapter 4.

7 2.2.2.5 Purchased Power Alternative

8 In this section, the NRC staff describes purchased power as an alternative to the continued 

9 operation of Byron. 

10 The impacts from purchased power would depend substantially on the generation technologies 

11 used to supply the purchased power. Impacts from operation of other electricity generators 

12 would likely occur in the ROI. As discussed in Section 2.2.1, replacement power for Byron 

13 would be required in northern Illinois and could come from anywhere within Illinois or adjoining 

14 states in either the PJM or MISO Regional Transmission Organizations (RTOs). Given the large 

15 geographic area, multiple RTOs within the ROI, and wide-ranging generating facilities, the NRC 

16 staff considers purchased power to be a feasible source of baseload power to replace Byron by 

17 the time the licenses expire in 2024 and 2026. 

18 Purchased power would likely come from the most common types of electricity generation within 

19 the ROI: coal, natural gas, nuclear, and wind. All of these power sources are discussed as 

20 alternatives to license renewal of Byron and are identified in Sections 2.2.2.2 to 2.2.2.4. 

21 Construction and operational impacts from these sources of electricity generation are 

22 considered in Chapter 4. Unlike the alternatives considered in Chapter 4, however, facilities 

23 from which power would be purchased would not likely be constructed solely to replace Byron. 

24 Purchased power may, however, require new transmission lines (which may require new 

25 construction) and may also rely on older and less-efficient power plants operating at higher 

26 capacities than they currently operate or new facilities that would be constructed. During 

27 operations, impacts from nuclear, coal-fired, and natural gas-fired plants, wind, and solar energy 

28 projects would be similar to that described under the new nuclear, coal, natural gas, and 

29 combination alternatives described in Chapter 4 for all resource areas. Impacts to air quality 

30 from the operations of existing coal and natural gas-fired plants would likely be greater than the 

31 operations of new plants because older plants are more likely to be less efficient and without 

32 modern emissions controls. Impacts to other resource areas from the operation of existing 

33 power plant facilities would likely be less than those for new plants because existing facilities 

34 would not require new construction.

35 2.3 Alternatives Considered but Dismissed

36 Alternatives to Byron license renewal that were considered and eliminated from detailed study 

37 are presented in this section. These alternatives were eliminated because of technical resource 

38 availability or current commercial limitations. Many of these limitations would continue to exist 

39 when the current Byron licenses expire.

40 2.3.1 Energy Conservation and Energy Efficiency 

41 Energy conservation can include reducing energy demand through behavioral changes or 

42 altering the shape of the electricity load and usually does not require the addition of new 

43 generating capacity. Conservation and energy efficiency programs are more broadly referred to 

44 as demand-side management (DSM). 
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1 Conservation and energy efficiency programs can be initiated by a utility, by transmission 

2 operators, by the state, or by other load-serving entities. The State of Illinois’ renewable 

3 portfolio standard includes an energy efficiency portfolio standard that requires utilities to reduce 

4 electric usage by 2 percent of demand by 2015 (DSIRE 2012a), which is equivalent to 

5 4 million MWh, only 20 percent of the amount that would be required to offset Byron’s current 

6 electrical generation. 

7 In general, residential electricity consumers have been responsible for the majority of peak load 

8 reductions, and participation in most programs is voluntary. Therefore, the existence of a 

9 program does not guarantee that reductions in electricity demand would occur. The GEIS

10 concludes that while the energy conservation or energy efficiency potential in the United States 

11 is substantial, there are likely no cases where an energy efficiency or conservation program has 

12 been implemented expressly to replace or offset a large baseload generation station 

13 (NRC 2013a). While significant energy savings are possible in the ROI through DSM and 

14 energy efficiency programs, conservation and energy efficiency programs are not likely to 

15 replace Byron as a standalone alternative, and therefore the NRC staff does not consider 

16 conservation and energy efficiency to be a reasonable alternative to license renewal. 

17 2.3.2 Solar

18 Solar power, including solar photovoltaic and concentrated solar power technologies, produce 

19 power generated from sunlight. Photovoltaics convert sunlight directly into electricity using solar 

20 cells, made from silicon or cadmium telluride. Concentrating solar power uses heat from the 

21 sun to boil water and produce steam to drive a turbine connected to a generator to produce 

22 electricity (NREL 2013d). To be considered a viable alternative, a solar alternative must replace 

23 the amount of electricity Byron provides. Assuming a capacity factor of 19 percent (Ardani and 

24 Margolis 2011), approximately 12,400 MWe of electricity would need to be generated by solar 

25 energy facilities in the seven-state ROI.

26 In 2011, 14 MWh of electricity was generated from solar energy in the ROI (EIA 2014c). DOE’s 

27 National Renewable Energy Laboratory (NREL) reports that the states in the ROI receive solar 

insolation of 4.0 to 5.0 kWh/m2 28 /day, which is considered low to average (NREL 2013c). For 

utility-scale development, insolation levels below 6.5 kWh/m2 29 /day are not considered 

30 economically viable given current technologies (BLM and DOE 2010). There is more potential 

31 for solar development using local photovoltaic applications, such as rooftop solar panels, than 

32 through utility-scale solar facilities. In addition, a solar facility can only generate electricity when 

33 the sun is shining. Energy storage can be used to overcome intermittency for concentrating 

34 solar power facilities; however, current and foreseeable storage technologies that have been 

35 paired with solar power facilities have a much smaller capacity than would be necessary to 

36 replace Byron. Taking all of the factors above into account, it is unlikely that solar photovoltaic 

37 or concentrated solar power technologies could serve as baseload power in the ROI to replace 

38 Byron’s current electricity output. Given the modest levels of solar energy available throughout 

39 the ROI, the lack of substantial installed solar capacity in the ROI and the weather-dependent 

40 intermittency of solar power, the NRC staff concludes that a solar power energy facility in the 

41 ROI would not be a reasonable alternative to license renewal. The NRC staff evaluated an 

42 alternative of solar power in combination with wind and an NGCC plant in Section 2.2.2.4. 

43 2.3.3 Wind

44 Two states in the ROI have the third- and fourth-largest installed capacity in the Nation: Iowa 

45 with 5,133 MW, followed by Illinois with 3,568 MW (AWEA 2013). The installed wind capacity in 

46 the ROI has been increasing annually by 1,000 MWe to 2,500 MWe in each of the past 6 years, 
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1 for a total of over 11,000 MWe of additional wind capacity from 2007 to 2012 (DOE 2013a). All 

2 of the wind energy facilities and the electricity generation from wind currently being produced in 

3 the ROI are land-based. To be considered a viable alternative, a wind alternative must replace 

4 the amount of electricity Byron provides. Assuming a capacity factor of 30 percent for 

5 land-based wind and 40 percent for offshore wind, a range of 5,665 to 7,553 MWe of electricity 

6 would need to be generated by some combination of land-based and offshore wind energy 

7 facilities in the seven-state ROI.

8 As is the case with other renewable energy sources, the feasibility of wind resources serving as 

9 alternative baseload power is dependent on the location (relative to expected load centers), 

10 value, accessibility, and constancy of the resource. Wind energy must be converted to 

11 electricity at or near the point where it is extracted, and there are limited energy storage 

12 opportunities available to overcome the intermittency and variability of wind resource availability. 

13 Although wind power is intermittent and individual facilities are unable to provide baseload 

14 power, it has been proposed that multiple interconnected wind installations separated by long 

15 distances could function as a virtual power plant and provide baseload power since individual 

16 facilities would be exposed to different weather and wind conditions. To date, however, no 

17 states or utilities operate arrays of wind installations as virtual power plants.

18 Given the amount of wind capacity necessary to replace Byron and the intermittency of wind 

19 power, the NRC staff finds a completely wind-based alternative to be unreasonable. However, 

20 the NRC staff also concludes that, when used in combination with other technologies with 

21 inherently higher capacity factors, wind energy can provide a viable alternative. The NRC staff 

22 evaluated such a possible combination as described in Section 2.2.2.4.

23 2.3.3.1 Offshore Wind 

24 The United States does not have any offshore wind farms in operation; however, approximately 

25 20 projects representing more than 2,000 MW of capacity are in the planning and permitting 

26 process as of 2010 (Musial and Ram 2010). Offshore wind projects have been developed in 

27 Europe, most of which are located close to shore and in shallow water less than 98.4 ft (30 m) in 

28 depth. Total worldwide installed capacity has been estimated at 2,377 MW (Musial and 

29 Ram 2010). 

30 While wind data suggest there is potential for offshore wind farms in the Great Lakes, project 

31 costs likely will limit the future potential of large-scale projects (Tidball et al. 2010). NREL 

32 (Tidball et al. 2010) estimated that offshore project costs would run approximately 200 to 

33 300 percent higher than land-based systems. In addition, based on current prices for wind 

34 turbines, the 20-year levelized cost of electricity produced from an offshore wind farm would be 

35 above the current production costs from existing power generation facilities. In addition to cost, 

36 other barriers include the immature status of the technology, limited resource area, and high 

37 risks and uncertainty (Tidball et al. 2010). As no offshore wind capacity yet exists in either the 

38 Great Lakes or on the Atlantic Coast and as none appears likely to exist on a large commercial 

39 scale in the Great Lakes by 2024 (given the current state of development), the NRC staff finds 

40 that offshore wind will not be a reasonable alternative to Byron. 

41 2.3.3.2 Wind Power with Storage

42 Energy storage is one possible way to overcome intermittency. Besides pumped hydroelectric 

43 facilities, compressed air energy storage (CAES) is the technology most suited for storage of 

44 large amounts of energy. In CAES systems, electricity generated during low-demand periods 

45 can be stored by using a compressor to pressurize and store air, and during high-demand 

46 periods, the compressed air can be used to drive a turbine to generate electricity. A 2011 DOE

47 report analyzed various power generation sources, including wind, coupled with CAES systems 
Alternatives Including the Proposed Action

2-21

1 (Ilic et al. 2011). The report considered siting criteria, using (1) proximity to natural gas lines, 

2 high voltage transmission, and a market for wholesale electric power and (2) availability of 

3 geology and wind resources. The results show that within the ROI there is potential for one 

4 CAES site in northwestern Iowa. Without detailed wind-speed data, specific site information, 

5 and detailed information on the energy-storage capacity of the potential CAES site, it is difficult 

6 to estimate how much wind capacity would be necessary and whether or not it could provide for 

7 an all-wind alternative. Furthermore, the NRC staff is not aware of a CAES project coupled with 

8 wind generation that is providing baseload power. Therefore, the NRC staff concludes that the 

9 use of CAES in combination with wind turbines to replace the Byron power plant is unlikely.

10 2.3.3.3 Conclusion

11 Despite the relatively high reliability demonstrated by modern turbines, the recent technological 

12 advancements in turbine design and wind farm operation, and wind energy’s dramatic market 

13 penetrations of recent years, empirical data on wind farm capacity factors and wind energy’s 

14 limited ability to store power for delayed production of electricity cause the NRC staff to 

15 conclude that wind energy—on shore, off shore, or a combination thereof—could not serve as a 

16 discrete alternative to the baseload power supplied by the Byron reactors. However, the NRC 

17 staff also concludes that, when used in combination with other technologies with inherently 

18 higher capacity factors, wind energy can provide a viable alternative. The NRC staff evaluated 

19 such a possible combination as described in Section 2.2.2.4. 

20 2.3.4 Biomass

21 Biomass resources used for biomass-fired generation include agricultural residues, animal 

22 manure, wood wastes from forestry and industry, residues from food and paper industries, 

23 municipal green wastes, dedicated energy crop, and methane from landfills (IEA 2007). Using 

24 biomass-fired generation for baseload power depends on the geographic distribution, available 

25 quantities, constancy of supply, and energy content of biomass resources. For this analysis, the 

26 NRC staff assumed that biomass would be combusted for power generation in the electricity 

27 sector. Biomass is also used for space heating in residential and commercial buildings and can 

28 be converted to a liquid form for use in transportation fuels (Haq undated).

29 In the GEIS, the NRC staff indicated a wood waste facility could provide baseload power and 

30 operate with capacity factors between 70 and 80 percent (NRC 2013a). Although the ROI 

31 currently produces electricity from biomass fuels, the plants operating within the ROI generated 

32 less than 1 percent of the total power generation in 2011 (EIA 2014c). Based on the relatively 

33 low electricity generation currently produced at biomass plants, it is unlikely that these plants, or 

34 the construction of several new biomass plants, could increase capacity by adding 2,336 MWe 

35 of electricity from biomass-fired generation by the time Byron’s licenses expire in 2024 and 

36 2026. 

37 For utility-scale biomass electricity generation, the NRC staff assumes that the technologies 

38 used for biomass conversion would be similar to fossil fuel plants including the direct 

39 combustion of biomass in a boiler to produce steam (NRC 2013a). Biomass generation is 

40 generally more cost-effective when cofired with coal plants (IEA 2007). Biomass-fired 

41 generation plants generally are small and can reach capacities of 50 MWe, meaning that more 

42 than 40 new facilities would be required before the Byron licenses expire. After reevaluating 

43 current technologies, the NRC staff finds biomass-fired alternatives as still unable to reliably 

44 replace the Byron capacity. For this reason, the NRC staff does not consider biomass to be a 

45 reasonable alternative to Byron license renewal.
Alternatives Including the Proposed Action

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1 2.3.5 Hydroelectric

2 Hydroelectric power uses the force of water to turn turbines which spin a generator to produce 

3 electricity. In a run-of-the-river system, the force of a river current provides the force to create 

4 the needed pressure for the turbine. In a storage system, water is accumulated in reservoirs 

5 created by dams and is released as needed to generate electricity. 

6 DOE’s Idaho National Environmental Engineering Laboratory (INEEL) (now Idaho National 

7 Laboratory) completed a comprehensive survey of hydropower resources in 1997. The ROI has 

8 hydroelectric generating potential of 1,954 MW, adjusting for environmental, legal, and 

9 institutional constraints (Conner et al. 1998). These constraints could include (1) scenic, 

10 cultural, historical, and geological values; (2) Federal and state land use; and (3) legal 

11 protection issues, such as Wild and Scenic legislation and Threatened or Endangered Fish and 

12 Wildlife legislative protection. A separate assessment by DOE of nonpowered dams (dams that 

13 do not produce electricity) concluded that there is potential for 4,185 MW of electricity in the ROI 

14 (ORNL 2012). These nonpowered dams serve various purposes such as providing water 

15 supply to inland navigation. 

16 EIA reported that the states composing the ROI generated 2,262 MW electricity from 

17 hydroelectric power in 2012 (EIA 2014b). In order to replace Byron’s current output, 

18 hydroelectric generation across the ROI would need to double by 2024. Although there is 

19 potential for anywhere between 1,954 MW and 4,185 MW of hydroelectric power, it is unlikely 

20 that the maximum levels of development would occur across the entire ROI by the time Byron’s 

21 licenses expire in 2024 and 2026 given that generating capacity of hydroelectric power is 

22 projected to continue decreasing through 2040 (EIA 2013b). Given the decrease in projected 

23 power generation from hydroelectric facilities, the NRC staff does not consider hydroelectric 

24 power to be a reasonable alternative to license renewal.

25 2.3.6 Wave and Ocean Energy

26 Waves, currents, and tides are often predictable and reliable, making them attractive candidates 

27 for potential renewable energy generation. Four major technologies may be suitable to harness 

28 wave energy: terminator devices that range from 500 kW to 2 MW, attenuators, point 

29 absorbers, and overtopping devices (BOEM undated). Point absorbers and attenuators use 

30 floating buoys to convert wave motion into mechanical energy, driving a generator to produce 

31 electricity. Overtopping devices trap a portion of a wave at a higher elevation than the sea 

32 surface; waves then enter a tube, compressing air that is used to drive a generator that 

33 produces electricity (NRC 2013a). Some designs are undergoing demonstration testing at 

34 commercial scales, but none are currently used to provide baseload power (BOEM undated). 

35 The Great Lakes do not experience large tides, and there is limited energy output for wave 

36 technologies in the Great Lakes. The Electric Power Resource Institute (EPRI) published a 

37 document that assessed ocean wave energy resources in the United States. The Great Lakes 

38 were not included in the analysis, suggesting that the resource potential is not great enough to 

39 use on a commercial scale (EPRI 2011). Consequently, the limited resource availability and 

40 infancy of the technologies in the Great Lakes support the NRC staff’s conclusion that wave and 

41 ocean energy technologies are not feasible substitutes for Byron.

42 2.3.7 Fuel Cells

43 Fuel cells oxidize fuels without combustion and its environmental side effects. Fuel cells use a 

44 fuel (e.g., hydrogen) and oxygen to create electricity through an electrochemical process. The 

45 only byproducts (depending on fuel characteristics) are heat, water, and carbon dioxide
Alternatives Including the Proposed Action

2-23

1 (depending on hydrogen fuel type) (DOE undated a). Hydrogen fuel can come from a variety of 

2 hydrocarbon resources. Natural gas is a typical hydrogen source.

3 Fuel cells are not economically or technologically competitive with other alternatives for 

4 electricity generation. EIA projects that fuel cells may cost $6,835 per installed kW (total 

5 overnight capital costs, 2010 dollars), which is high compared to other alternative technologies 

6 analyzed in this section (EIA 2010). More importantly, fuel cell units are likely to be small in size 

7 (approximately 10 MWe). It would be extremely costly to replace the power Byron provides; it 

8 would require approximately 230 units and modifications to the existing transmission system. 

9 Given the immature status of fuel cell technology and high cost, the NRC staff does not consider 

10 fuel cells to be a reasonable alternative to Byron license renewal.

11 2.3.8 Delayed Retirement

12 A delayed retirement alternative would consider deferring the retirement of generating facilities 

13 in Illinois and its six adjoining states that include MISO and PJM RTOs.

14 To maintain reliable operations, electric systems must be able to meet peak load requirements. 

15 To ensure sufficient capacity, this must also include a planning reserve margin (FERC 2013). 

16 The projected MISO reserve margin for 2021 is 18.6 percent, which exceeds the reserve margin 

17 requirement of 17.4 percent. However, pending EPA regulations may lead to increased coal 

18 plant retirements at a faster pace than projected. In that case, 3,000 MW to 12,600 MW of plant 

19 retirements could decrease the projected reserves anywhere from 16.22 to 6.9 percent, well 

20 below the reserve margin requirement (MISO 2011). 

21 PJM is facing similar constraints due, in large part, to retirements of coal plants given air quality 

22 regulations (Ott 2013a). This indicates an emerging reliability problem potentially affecting 

23 major population centers within the PJM region in the near future (Ott 2013a). Because the 

24 current generation mix has not resulted in the long-term commitment of generation needed for 

25 reliability, generation retirements that have occurred with short notice have created 

26 unanticipated reliability problems for PJM (Ott 2013a).

27 The 2014 Annual Energy Outlook predicts that there will be more coal plant retirements before 

28 2016 than previously predicted. These accelerated retirements are driven by low natural gas 

29 prices, slow growth in electricity demand, and the requirements of the Mercury and Air Toxics 

30 Standards (MATS) that will require significant reductions in plant emissions (EIA 2014a). 

31 Exelon also expects increased generation retirements for a variety of reasons, including 

32 increased operating costs for older facilities, increased environmental regulations and 

33 competition, and decreased load (Exelon undated). As generators are required to adhere to 

34 future regulations, some power plants may opt for early retirement of older units rather than 

35 incur the cost for compliance. Exelon has further stated that some of their nuclear fleet may be 

36 retired early because of low wholesale energy prices and current energy policy 

37 (Bloomberg 2014). Because of the uncertain regulatory environment and concerns expressed 

38 by MISO and PJM concerning the retirement pace of coal power plants, the NRC staff does not 

39 consider delayed retirement to be a reasonable alternative to Byron license renewal.

40 2.3.9 Geothermal

41 Geothermal technologies extract the heat contained in geologic formations to produce steam to 

42 drive a conventional steam turbine generator. Facilities producing electricity from geothermal 

43 energy have demonstrated capacity factors of 95 percent or greater, making geothermal energy 

44 a potential source of baseload electric power. However, the feasibility of geothermal power 

45 generation to provide baseload power depends on the regional quality and accessibility of 
Alternatives Including the Proposed Action

2-24

1 geothermal resources. Utility-scale geothermal energy generation requires geothermal 

2 reservoirs with a temperature above 200 °F (93 °C). Utility-scale power plants range from small 

3 300 kilowatts electric (kWe) to 50 MWe and greater (TEEIC undated). Geothermal resources 

4 are concentrated in the western United States. Specifically, these resources are found in 

5 Alaska, Arizona, California, Colorado, Hawaii, Idaho, Montana, Nevada, New Mexico, Oregon, 

6 Utah, Washington, and Wyoming (USGS 2008). In general, most assessments of geothermal 

7 resources have been concentrated on these western states. The DOE has also quantified 

8 geothermal resources in Minnesota and Vermont but not in any of the states that compose the 

9 ROI (DOE 2013c). Geothermal resources are used in the ROI for heating and cooling 

10 purposes, but no electricity is currently being produced from geothermal resources in the ROI 

11 (EIA 2014c). Given the low resource potential in the ROI, the NRC staff does not consider 

12 geothermal to be a reasonable alternative to license renewal.

13 2.3.10 Municipal Solid Waste

14 Energy recovery from municipal solid waste converts nonrecyclable waste materials into usable 

15 heat, electricity, or fuel through combustion (EPA 2013b). The three types of combustion 

16 technologies include mass burning, modular systems, and refuse-derived fuel systems 

17 (EPA 2013a). Mass burning is the method used most frequently in the United States. The heat 

18 released from combustion is used to convert water to steam, which is used to drive a turbine 

19 generator to produce electricity. Ash is collected and taken to a landfill and particulates are 

20 captured through a filtering system (EPA 2013a). As of 2010, approximately 86 waste-to21 energy plants are in operation in 25 states, processing more than 28 million tons of waste per 

22 year (EPA 2013b). These waste-to-energy plants have an aggregate capacity of 2,720 MWe, 

23 and although some plants have expanded to handle additional waste and produce more energy, 

24 no new plants have been built in the United States since 1995 (EPA 2013b). The average 

25 waste-to-energy plant produces about 50 MWe, with some reaching 77 MWe, and can operate 

26 at capacity factors greater than 90 percent (Michaels 2010). Indiana has one waste recovery 

27 facility that produces steam; Iowa has one waste-to-energy facility that produces 10 MW of 

28 electricity; Michigan has three facilities that produce 89.7 MW of electricity; and Wisconsin has 

29 two facilities that generate 32.3 MW of electricity (Michaels 2010). In total, as of 2010, the ROI 

30 had a municipal solid waste generating capacity of 132 MW. More than 46 average-sized plants 

31 would be necessary to provide the same level of output as Byron, almost doubling the national 

32 waste-to-energy generation.

33 The decision to burn municipal waste to generate energy is usually driven by the need for an 

34 alternative to landfills rather than energy considerations. Given the improbability that additional 

35 stable supplies of municipal solid waste would be available to support approximately 46 new 

36 facilities and that so few existing plants operate in the ROI, the NRC staff does not consider 

37 municipal solid waste combustion to be a reasonable alternative to Byron license renewal.

38 2.3.11 Petroleum

39 In the ROI, oil-fired generation in 2012 had a generating capacity of 4,986 MW (EIA 2014b).

40 The variable costs of oil-fired generation tend to be greater than those of the nuclear or 

41 coal-fired operations, and oil-fired generation tends to have greater environmental impacts than 

42 natural gas-fired generation. The high cost of oil has resulted in a steady decline in its use for 

43 electricity generation (EIA 2013a). Given the high cost of oil and the small generating capacity 

44 from oil-fired power plants in the ROI, the NRC staff does not consider oil-fired generation a 

45 reasonable alternative to Byron license renewal.
Alternatives Including the Proposed Action

2-25

1 2.3.12 SCPC

2 In general, SCPC power plants are feasible, commercially available options for providing 

3 electrical generating capacity. Baseload coal units have proven their reliability and can sustain 

4 capacity factors as high as 79 percent. Pulverized coal power generation uses crushed coal 

5 that is fed into a boiler where it is burned to create heat. The heat produces steam that is used 

6 to spin one or more turbines to generate electricity. Among the technologies available, 

7 pulverized coal boilers producing supercritical steam (SCPC boilers) are increasingly common 

8 for new coal-fired plants given their high operating temperatures and pressures that increase 

9 thermal efficiencies and overall reliability. SCPC facilities consume less fuel per unit output, 

10 reducing environmental impacts (NETL undated). 

11 As described in Section 2.2.3, EPA has issued a proposed rule for carbon pollution that would 

12 apply to new fossil fuel-fired power plants, including SCPC facilities. The action proposes 

13 performance standards and has identified a CCS system as the best method of emission 

14 reduction. The proposed emission limit for these sources is 1,100 lb CO2/MWh. EIA modeling 

15 projects that if the proposed rule were implemented, few, if any, new coal-fired units would be 

16 built and that those that are built would include CCS (79 FR 1430). If this rule becomes final, 

17 any new coal-fired power plants would likely require CCS in order to achieve the 1,100 lb 

18 CO2/MWh emission limit.

19 In addition, given known technology and technological and demographic trends, EIA predicts 

20 that by 2040 natural gas will surpass coal as the largest share of U.S. electric power generation 

21 (EIA 2013a). This does not consider the proposed EPA rule described above, but indicates a 

22 general trend away from coal-fired facilities in favor of natural gas-fired power plants due to 

23 falling natural gas prices. MISO projects that the pending EPA regulations could lead to 

24 increased coal plant retirements, and estimates retirements between 3,000 MW to 12,600 MW, 

25 which could have a large impact on MISO’s reserve margin in the future (MISO 2011).

26 Although SCPC plants are currently the most widely used source of electricity generation within 

27 the ROI, given the potential for stringent air quality regulations and trends towards natural 

28 gas-fired power plants, the NRC staff does not consider SCPC to be a reasonable alternative to 

29 Byron license renewal. Instead, the NRC staff describes an IGCC plant under the coal 

30 alternative in Section 2.2.2.2. 

31 2.4 Comparison of Alternatives

32 In this chapter, the NRC staff considered the following alternatives to Byron license renewal: 

33 new nuclear generation; IGCC generation; NGCC generation; a combination alternative of 

34 natural gas, wind, and solar; and purchased power. The no-action-by-NRC alternative and its 

35 effects also were considered. The impacts for all alternatives to Byron license renewal are 

36 discussed in Chapter 4 and summarized in Table 2–2 below.

37 The environmental impacts of the proposed action (issuing renewed Byron operating licenses) 

38 would be SMALL for all impact categories. The environmental impacts from all other 

39 alternatives would be larger than the proposed license renewal, as indicated in Table 2–2. 
2-26

Table 2–2. Summary of Environmental Impacts of Proposed Action and Alternatives 1 

Impact Area

(Resource)

Byron

License 

Renewal 

(Proposed 

Action)

No-Action New Nuclear 

Alternative

IGCC 

Alternative

NGCC 

Alternative

Combination 

Alternative

(NGCC, Wind

Solar)

Land Use and Visual Resources

Land Use SMALL SMALL SMALL SMALL TO 

MODERATE SMALL SMALL TO MODERATE 

Visual Resources SMALL SMALL SMALL TO 

MODERATE

SMALL TO 

MODERATE

SMALL TO 

MODERATE

SMALL TO 

LARGE 

Air Quality and Noise

Air Quality SMALL SMALL SMALL MODERATE MODERATE SMALL TO 

MODERATE

Noise SMALL SMALL SMALL SMALL TO 

MODERATE SMALL SMALL TO MODERATE

Geologic 

Environment SMALL SMALL SMALL SMALL SMALL SMALL 

Water Resources

Surface Water

Resources SMALL SMALL SMALL TO MODERATE

SMALL TO 

MODERATE SMALL SMALL 

Groundwater

Resources SMALL SMALL SMALL SMALL SMALL SMALL 

Terrestrial Resources SMALL SMALL SMALL TO 

MODERATE MODERATE SMALL TO MODERATE

SMALL TO 

MODERATE 

Aquatic Resources SMALL SMALL SMALL SMALL TO 

MODERATE

SMALL TO 

MODERATE SMALL 

Special Status 

Species and Habitats NO EFFECT SEE NOTE1 SEE NOTE1 SEE NOTE1 SEE NOTE1 SEE NOTE1 

Historic and Cultural

Resources SEE NOTE 2 NO EFFECT SMALL SMALL SMALL TO MODERATE

SMALL TO 

LARGE
2-27

Impact Area

(Resource)

Byron

License 

Renewal 

(Proposed 

Action)

No-Action New Nuclear 

Alternative

IGCC 

Alternative

NGCC 

Alternative

Combination 

Alternative

(NGCC, Wind

Solar)

Socioeconomics

Socioeconomics SMALL SMALL TO 

LARGE

SMALL TO 

MODERATE

SMALL TO 

MODERATE

SMALL TO 

MODERATE SMALL 

Transportation SMALL SMALL SMALL TO 

MODERATE

SMALL TO 

MODERATE

MODERATE 

TO LARGE

SMALL TO 

MODERATE

Human Health SMALL SMALL SMALL SMALL SMALL SMALL 

Environmental 

Justice SEE NOTE 3

 SEE NOTE 4 SEE NOTE 5 SEE NOTE 6 SEE NOTE 7 SEE NOTE 8 

Waste Management

and Pollution 

Prevention

SMALL SMALL SMALL SMALL TO 

MODERATE SMALL SMALL 

Notes:

1 The magnitude of impacts could vary widely based on site selection and the presence or absence of special status species an

the alternative is implemented; thus, the NRC staff cannot forecast a level of impact for this alternative. 2 Based on (1) there being currently no NRHP-eligible historic properties in the APE, (2) tribal input, (3) Exelon’s draft CRMP, (4

license renewal-related physical changes or ground-disturbing activities would occur, (5) IHPA input, and (6) cultural resource 

license renewal would not affect any known historic properties (36 CFR Section 800.4(d)(1)). 3 Continued operation of Byron would not have disproportionately high and adverse human health and environmental effects on 

populations. 4 The No-Action Alternative could disproportionately affect minority and low-income populations that may have become depend

services in Ogle County. 5 The new nuclear alternative would not have disproportionately high and adverse human health and environmental effects on m

low-income populations. 6 The IGCC Alternative would not have disproportionately high and adverse human health and environmental effects on minorit

populations. 7 The NGGC Alternative would not have disproportionately high and adverse human health and environmental effects on minor

low-income populations. 8 The Combination Alternative would not have disproportionately high and adverse human health and environmental effects on 

low-income populations. 9 The Purchased Power Alternative could be disproportionately affect low-income populations by increased utility bills because 

purchased power. However, programs, such as the low income home energy assistance program in Illinois, are available to a

families in paying for increased electrical costs.
Alternatives Including the Proposed Action

2-28

1 In conclusion, the environmentally preferred alternative is the granting of a renewed license for 

2 Byron. All other alternatives capable of meeting the needs currently served by Byron entail 

3 potentially greater impacts than the proposed action of renewing the license for Byron. To make 

4 up the lost generation if a renewed license is not issued (the no-action alternative), one or a

5 combination of alternatives would be implemented, all of which have greater impacts than the 

6 proposed action. Hence, the NRC staff concludes that the no-action alternative will have 

7 environmental impacts greater than or equal to the proposed license renewal action. 

8 2.5 References

9 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic licensing of 

10 production and utilization facilities.”

11 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

12 protection regulations for domestic licensing and related regulatory functions.”

13 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

14 renewal of operating licenses for nuclear power plants.”

15 79 FR 1430. U.S. Environmental Protection Agency. “Standards of performance for greenhouse

16 gas emissions from new stationary sources: electric utility generating units.” Federal 

17 Register 79(5):1430–1519. January 8, 2014. 

18 AmerenUE. 2009. Callaway Plant Unit 2 Combined License Application Part 3: Environmental 

19 Report. Revision 1. February 2009. 1,444 p. ADAMS No. ML090710402.

20 Archer CL, Jacobson MZ. 2007. Supplying baseload power and reducing transmission 

21 requirements by interconnecting wind farms. Journal of Applied Meteorology and 

22 Climatology 46(11):1701–1717. Available at 

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24 Ardani K, Margolis R. 2011. 2010 Solar Technologies Market Report. Golden, CO: National 

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26 <http://www.nrel.gov/docs/fy12osti/51847.pdf> (accessed 1 December 2013).

27 [AWEA] American Wind Energy Association. 2013. AWEA U.S. Wind Industry First Quarter 

28 2013 Market Report Executive Summary. April 30, 2013. 7 p. Available at

29 <http://awea.files.cms-plus.com/FileDownloads/pdfs/

30 AWEA%20US%20Wind%20Industry%201Q%202013%20Market%20Report_Executive%20

31 Summary.pdf> (accessed 26 November 2013).

32 [BLM and DOE] U.S. Department of the Interior Bureau of Land Management and

33 U.S. Department of Energy. 2010. Draft Programmatic Environmental Impact Statement for 

34 Solar Energy Development in Six Southwestern States. DES 10-59; DOE/EIS-0403, Volumes 1 

35 to 8. December 2010. 11,145 p. Available at

36 <http://www.solareis.anl.gov/documents/dpeis/index.cfm#vol1> (accessed 26 November 2013).

37 [BLM and DOE] U.S. Department of the Interior Bureau of Land Management and

38 U.S. Department of Energy. 2012. Final Programmatic Environmental Impact Statement (PEIS) 

39 for Solar Energy Development in Six Southwestern States. FES 12-24; DOE/EIS-0403, 

40 Volumes 1 to 7. July 2012. 3,596 p. Available at

41 <http://www.solareis.anl.gov/documents/fpeis/index.cfm> (accessed 26 November 2013).

42 [Bloomberg] Bloomberg Businessweek. 2014. “AP Digital: Nuclear power company to consider

43 plant closures.” February 14, 2014. Available at <http://www.businessweek.com/ap/

44 2014-02-14/nuclear-power-company-to-consider-plant-closures> (accessed 18 February 2014).
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1 [BOEM] Bureau of Ocean Energy Management. undated. “Ocean Wave Energy.” Available at 

2 <http://www.boem.gov/Renewable-Energy-Program/Renewable-Energy-Guide/

3 Ocean-Wave-Energy.aspx> (accessed 20 January 2014).

4 Channell J, Lam T, Pourreza S. 2012. Shale & renewables: a symbiotic relationship. CITI 

5 Research. September 12, 2012. 88 p. Available at <http://www.ourenergypolicy.org/

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13 Report. Idaho Falls, ID: Idaho National Engineering and Environmental Laboratory. 

14 DOE/ID-10430.2. December 1998. 49 p. Available at 

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16 [DOE] U.S. Department of Energy. 2010a. Kemper County Integrated Gasification 

17 Combined-Cycle (IGCC) Project, Final Environmental Impact Statement (EIS). Washington, DC: 

18 DOE. DOE/EIS-0409, Volume 1. May 2010. 671 p. Available at 

19 <http://energy.gov/sites/prod/files/nepapub/nepa_documents/RedDont/

20 EIS-0409-FEIS-01-2010.pdf> (accessed 26 November 2013).

21 [DOE] U.S. Department of Energy. 2010b. Final Environmental Assessment for Department of 

22 Energy Loan Guarantee for the Agua Caliente Solar Project in Yuma County, Arizona. 

23 DOE/EA-1797. November 2010. Available at 

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25 (accessed 9 July 2014).

26 [DOE] U.S. Department of Energy. 2013a. “WINDExchange: U.S. Installed Wind Capacity.”

27 Available at <http://www.windpoweringamerica.gov/wind_installed_capacity.asp> (accessed

28 15 January 2014).

29 [DOE] U.S. Department of Energy. 2013c. “State Geothermal Resource Assessment and Data

30 Collection Efforts.” February 22, 2013. Available at

31 <http://www1.eere.energy.gov/geothermal/resource_assessments.html> (accessed

32 20 January 2014).

33 [DOE] U.S. Department of Energy. undated a. “Fuel Cell—Basics.” Available at 

34 <http://energy.gov/eere/fuelcells/fuel-cells-basics> (accessed 21 January 2014).

35 [DOE] U.S. Department of Energy. undated b. “Small Modular Nuclear Reactors.” Available at

36 <http://energy.gov/ne/nuclear-reactor-technologies/small-modular-nuclear-reactors> (accessed

37 20 January 2014).

38 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2012a. “Illinois Renewable 

39 Portfolio Standard.” September 7, 2012. Available at

40 <http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=IL04R> (accessed 

41 26 November 2013).

42 [DSIRE] Database of State Incentives for Renewable Energy. 2012b. “Database of State 

43 Incentives for Renewables and Efficiency. Iowa Incentives/Policies for Renewables and 

44 Efficiency: Alternative Energy Law.” Available at

45 <http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=IA01R&re=1&ee=0> 

46 (accessed 26 November 2013). 
Alternatives Including the Proposed Action

2-30

1 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2012c. “Wisconsin 

2 Renewable Portfolio Standard.” December 14, 2012. Available at 

3 <http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=WI05R> (accessed 

4 26 November 2013).

5 [DSIRE] Database of State Incentives for Renewable Energy. 2012d. “Database of State 

6 Incentives for Renewables and Efficiency. Indiana Incentives/Policies for Renewables and 

7 Efficiency: Clean Energy Portfolio Goal.” Available at 

8 <http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=IN12R&re=0&ee=0> 

9 (accessed November 26, 2013). 

10 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2013a. “Michigan 

11 Renewable Energy Standard.” February 5, 2013. Available at

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13 26 November 2013). 

14 [DSIRE] Database of State Incentives for Renewables & Efficiency. 2013b. “Missouri 

15 Renewable Electricity Standard.” July 29, 2013. Available at

16 <http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=MO08R> (accessed 

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30 Upper Great Plains Wind Energy Programmatic Environmental Impact Statement, Draft. 

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33 26 November 2013).
3-1 

1 3.0 AFFECTED ENVIRONMENT

2 In this supplemental environmental impact statement (SEIS), the “affected environment” is the 

3 environment that currently exists at and around Byron Station, Units 1 and 2 (Byron). Because 

4 existing conditions are at least partially the result of past construction and operation at the plant, 

5 the impacts of these past and ongoing actions and how they have shaped the environment are 

6 presented here. The facility and its operation are presented in Section 3.1. The affected 

7 environment is presented in Sections 3.2 to 3.13.

8 3.1 Description of Nuclear Power Plant Facility and Operation

9 Byron is a two unit nuclear power plant located in Ogle, Illinois. It began commercial operation 

10 in February 1985 (Unit 1) and January 1987 (Unit 2). Generally, the U.S. Nuclear Regulatory 

11 Commission (NRC) staff drew information about Byron’s facilities and operation from Exelon 

12 Generation Company, LLC’s (Exelon’s) Environmental Report (ER) (Exelon 2013a). 

13 3.1.1 External Appearance and Setting 

14 The Byron site is in northern Illinois near the center of Ogle County, approximately 90 mi 

15 (145 km) west-northwest of Chicago, 17 mi (27 km) southwest of Rockford, and 3.7 mi (6 km) 

16 south-southwest of the City of Byron (Figure 3–1) (Exelon 2013a).

17 The site is located on approximately 1,782 acres (ac) (721 hectares (ha)), and consists of the 

18 main site area and a right-of-way (ROW) to the Rock River for the circulating water makeup 

19 intake and blowdown discharge pipelines (Figures 3–2 and 3–3). The main site area occupies 

20 approximately 1,398 ac (566 ha), while the water pipelines’ ROW occupies the remaining 

21 384 ac (155 ha) (Exelon 2013a). The water intake and discharge pipelines’ ROW runs from the 

22 northwest site boundary approximately 2 mi (3.2 km) west to the Rock River (Exelon 2013a). 

23 The Byron site’s main structures include two reactor containment structures and related 

24 facilities, two circulating water natural draft cooling towers, two essential service water 

25 mechanical draft cooling towers, a switchyard, and administration buildings, 

26 warehouses, and other features (Exelon 2013a).

27 There are three ROWs that connect Byron to the regional electrical grid. These ROWs, which 

28 total approximately 1,210 ac (490 ha), are owned and maintained by Commonwealth Edison 

29 Company (ComEd) (Exelon 2013a).
Affected Environment

3-2 

1 Figure 3–1. Byron 50-Mile Radius Map

2 

3 Source: Exelon 2013a

* Byron Units 1 & 2 

C:Jso-MIIe Radius 

Water 

--+--+- Railroad 

Major Highways 

= Limited Access 

~ Federal Land - Highway 

- MunicipaUMetropolitan Area --- Major Road 

~ ~ County 

c:::J State 

0 10 
Affected Environment

3-3 

1 Figure 3–2. Byron 6-Mile Radius Map

2 

3 Source: Exelon 2013a

Legend 

* Byron Units 1 & 2 

CJ Byron Site Boundary 

CJ 6-Mile Radius 

River/Stream 

Railroad 

--- Street 

Major Highways 

Limited Access 

~ County Highway 

-

. --- Major Road Municipal/Metropolitan Area 

German Church Rd. 

0.5 

Miles 

Illinois 
Affected Environment

3-4 

1 Figure 3–3. Byron Site Boundary

2 

3 Source: Exelon 2013a

Legend 

Former Dirk's 

Farm Property 

ln.take & Discharge Pipelines Route 

Transmission Line 

Street 

Water 

c=J Byron Plant Structures .. Municipal/Metropolitan Area 

c:::J Byron Site Boundary 

~ Byron Salvage Yard Superfund Site 

0 

Holcomb 

0.15 0.3 

* 

Illinois 

Whitaker 

N 

E w s 

0.6 

Miles 
Affected Environment

3-5 

1 The Byron Salvage Yard Superfund Site (Byron Salvage Site; not contaminated by activities at 

2 Byron) is by the north portion of the west side of the Byron site (Figure 3–3) and consists of two 

3 separate parcels: the Byron Salvage Yard and Dirk’s Farm. The Byron Salvage Site is 

4 administered by U.S. Environmental Protection Agency (EPA) Region 5 and was proposed for 

5 listing on the Superfund National Priorities List (NPL) in 1982. The Dirk’s Farm property is a 

6 former farm that is owned by Exelon and lies west of the Byron Salvage Yard. The Byron 

7 Salvage Yard property is a former automotive salvage yard and dump that is owned by ComEd. 

8 After the broader Byron Salvage Site was nominated for listing on the Superfund NPL, EPA 

9 performed a Remedial Investigation/Feasibility Study and initiated action under Superfund. In 

10 2000, a Consent Decree was entered for remedial work on the Dirk’s Farm property. The final 

11 remedial action for soils on the Dirk’s Farm property was completed by Exelon in 2003, ending 

12 its responsibilities under the Consent Decree. A long-term groundwater monitoring plan for the 

13 Byron Salvage Yard Superfund Site was approved by EPA in 2003 (Exelon 2013a).

14 3.1.2 Nuclear Reactor Systems

15 The nuclear reactor for each of the two Byron units is a Westinghouse pressurized-water reactor 

16 (PWR) with four steam generators. Byron Units 1 and 2 entered commercial service on 

17 September 16, 1985, and August 21, 1987, respectively. On June 23, 2011, Exelon submitted a 

18 license amendment request to the NRC to increase the maximum power levels based on 

19 measurement uncertainty recapture (MUR) (Exelon 2011d). On February 7, 2014, the NRC 

20 staff issued license amendments approving the MUR and raised the rated thermal power to 

21 3,645 megawatts thermal (NRC 2014a). At 100 percent reactor power, the combined net 

22 electrical output from both Byron units is approximately 2,370 megawatts electric 

23 (Exelon 2013a).

24 The Unit 1 steam generators are Babcock & Wilcox recirculating vertical U-tube units. The 

25 Unit 2 steam generators are Westinghouse recirculating vertical U-tube units. The original

26 Byron Unit 1 steam generators were replaced in 1998; the Byron Unit 2 steam generators are 

27 original to the plant. The reactor coolant pumps are Westinghouse vertical, single-stage, 

28 centrifugal pumps equipped with controlled-leakage shaft seals (Exelon 2013a).

29 The reactor containment structure for each unit is a steel-lined, post-tensioned concrete vertical 

30 cylinder with a reinforced concrete base and a shallow dome (Exelon 2013a).

31 Both Byron units are licensed for low-enriched uranium dioxide fuel with enrichment to a 

32 nominal 5.0 percent by weight of uranium-235 and an allowable fuel burnup not to exceed 

33 60,000 megawatt-days per metric ton (Mt) uranium. The uranium dioxide fuel is in the form of 

34 high-density ceramic pellets enclosed in Zircaloy-based tubing (Exelon 2013a).

35 3.1.3 Cooling and Auxiliary Water Systems

36 Byron uses a closed-cycle cooling tower-based heat dissipation system. In closed-cycle 

37 systems, water travels through the system to cool plant condensers and other system 

38 components and is then routed to cooling towers, which dissipate excess heat through 

39 evaporation. Water that is not lost to evaporation is either recirculated through the system as 

40 cooling water or discharged as blowdown (i.e., water that is periodically rinsed from the cooling 

41 system to remove impurities and sediment that may degrade plant performance) to a receiving 

42 water body. Water lost to evaporation or discharged as blowdown must be replaced; this 

43 replacement water is referred to as makeup water. Figure 3–4 provides a basic schematic 

44 diagram of a closed-cycle cooling system with a natural draft cooling tower. Byron has both 

45 natural draft cooling towers and mechanical draft cooling towers that service its three cooling 

46 and auxiliary water systems. All of Byron’s systems withdraw makeup water from and discharge
Affected Environment

3-6 

1 blowdown to the Rock River, which lies 2 mi (3.2 km) west of the Byron site’s northwestern 

2 boundary. Unless otherwise cited, the description of Byron’s cooling and auxiliary water 

3 systems is derived from Exelon’s Environmental Report (ER) (Exelon 2013a) and Exelon’s 

4 responses to the staff’s requests for additional information (RAI) dated December 19, 2013 

5 (Exelon 2013b).

6 Figure 3–4. Closed-Cycle Cooling System with Natural Draft Cooling Tower

7 

8 Source: NRC 2013a, modified from Figure 3.1-4 

9 3.1.3.1 Circulating Water System

10 The circulating water system provides cooling water to the main condensers to cool the Byron 

11 reactor cores. At 100 percent power, each reactor unit requires 693,000 gallons per minute 

(gpm) (1,540 cubic feet per second (cfs) (43.5 cubic meters per second (m3 12 /s))—

1,386,000 gpm (3,080 cfs (87 m3 13 /s)) in total—of circulating water to remove excess heat from 

14 the condensers. Following use for cooling, heated water is pumped to two natural draft cooling 

towers for heat dissipation where about 19,800 gpm (52.9 cfs (1.5 m3 15 /s) of water is lost to 

16 evaporation. The remaining water is routed to an open flume located between the two cooling 

17 towers. Water in the flume either enters the circulating water pump house, from which it is 

18 returned to the circulating water system, or it is discharged as blowdown. Byron discharges 

approximately 13,000 to 17,000 gpm (29 to 37.9 cfs (0.82 to 1.1 m3 19 /s) to the river as 

20 blowdown. Blowdown water travels from the flume through a 30-in. (76.2-cm) pipeline that runs 

21 west along Exelon’s 2-mi (3.2-km)-long ROW to the Rock River (see Figure 3–5). The outfall 

22 structure lies about 61 m (200 ft) downstream of the intake point at the river screen house 

23 (described below). From the outfall structure, water discharges to the river through an 84-m 

24 (275-ft)-long rip-rapped channel.
Affected Environment

3-7 

1 Figure 3–5. Byron Cooling Water Intake and Discharge Pipelines

2 

3 Source: Exelon 2013a, modified from Figure 2.1-3 

.. 

> 

rf 

Legend 

~~- Discharge Line 

-~ Intake Line 

--Street 

Water 

Cl Byron Plant Structures .. Municipal/Metropolitan Area 

C:J Byron Site Boundary 

)f II 

I 

,J 

015 0.3 

Wtttaker 

~ E 

s 

D.6 
Affected Environment

3-8 

1 To account for evaporative and blowdown losses, Byron’s circulating water intake system 

withdraws an average of 36,750 gpm (81.8 cfs (2.3 m3 2 /s)) of makeup water. Typically, the 

Rock River near Byron flows at a rate of 6,033 cfs (170 m3 3 /s) (see Section 3.5.1.1). During low 

river flow (i.e., less than 679 cfs (19.2 m3 4 /s), Byron has an agreement with the Illinois 

5 Department of Natural Resources (IDNR) to limit Rock River water consumption to no more 

6 than 9 percent of total river flow during times when the river flow is at or below the specified low 

7 river flow. Commonwealth Edison Company made this agreement with the Illinois Department 

8 of Transportation (IDOT), Division of Water Resources (now IDNR) in 1977 during the process 

9 for obtaining a permit to construct the Byron intake and discharge structures (IDOT 1977). The 

permit also imposes a maximum withdrawal rate of 46,700 gpm (125 cfs (3.5 m3 10 /s)) regardless 

11 of the volume of flow in the river. Exelon has since incorporated the implementation of these 

12 permit conditions into several site procedures.

13 Makeup water is withdrawn from the Rock River through an intake structure on the east bank of 

14 the river (referred to as the “river screen house”), which is located at river mile (RM) 115 (river 

15 kilometer (RKm) 185) (see Figure 3–5). The river screen house has three dedicated makeup 

pumps, each with a capacity of 24,000 gpm (54 cfs or 1.5 m3 16 /s). Two of the pumps support 

17 normal operations and one serves as a backup. Prior to entering the intake structure, water 

18 flows at a speed of 0.43 to 0.55 feet per second (fps) (0.13 to 0.17 meters per second (m/s)) 

19 through trash racks located outside of the river screen house. The trash racks remove large 

20 debris and ice (in winter months) and are spaced 3 in. (8 cm) apart and extend from the intake 

21 channel floor to a height of 28 ft (8.5 m). Water then enters the screen house and is routed 

22 through traveling screens with 3/8-in. (0.95-cm) wire mesh openings. The design through23 screen flow rate is 1.65 fps (0.5 m/s), but actual maximum through-screen velocity was 

24 measured as 0.91 fps (0.28 m/s) during preoperational impingement studies (IEPA 1989). The 

25 traveling screens operate automatically based on pressure differential, or if there is no pressure 

26 differential for a given period of time, every 12 hours for a period of 55 minutes. Debris and 

27 aquatic organisms collected on the screens are collected in trash baskets and disposed of off 

28 site. Following the traveling screens, circulating water makeup pumps direct water into a 48-in. 

29 (1.2-m) pipeline that runs approximately 2 mi (3.2 km) east from the river screen house to the 

30 boundary of the Byron site. The pipeline discharges into the flume between the cooling towers, 

31 at which point makeup water can enter the circulating water system through the circulating 

32 water pump house.

33 3.1.3.2 Nonessential Service Water System

34 The nonessential service water system provides water to non-safety-related systems. This 

35 system draws water from the circulating water pump house and returns water to the natural draft 

36 cooling towers. Makeup water from this system is supplied through the circulating water 

37 system’s infrastructure, which is described above.

38 3.1.3.3 Essential Service Water System

39 The essential service water system removes heat from the reactor safeguard and auxiliary 

40 systems. During normal operations, this system draws water from the circulating water pump 

41 house, which pumps water to the auxiliary building, at which point water enters the essential 

42 service water system. The essential service water system also includes two 12-in. (0.3-m) 

43 intake pipelines that are dedicated to providing a source of backup makeup water during 

44 conditions in which makeup is not available from the circulating water system. The makeup 

45 pipelines run parallel to the circulating water system makeup pipelines from the river screen 

46 house to the site boundary and then to the mechanical draft cooling towers. These 

47 two mechanical draft cooling towers serve as the ultimate heat sink for the plant’s two reactor 
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1 units. Blowdown from these cooling towers is routed to the flume between the circulating water 

2 system’s natural draft cooling towers.

3 3.1.3.4 Cooling and Auxiliary Water Treatment

4 Exelon treats each water system to prevent corrosion, scaling (i.e., the buildup of inorganic 

5 nutrients, such as calcium, magnesium, and silica), and biofouling. Exelon adds zinc to prevent 

6 corrosion; sulfuric acid, polyphosphate, potassium phosphate, acrylic polymer, and triazole to 

7 prevent scaling; sodium hypochlorite and sodium bromide to makeup water to prevent 

8 biofouling; and polyacrylate to disperse silt. Circulating water system makeup water is also 

9 treated with a low concentration of copper ions to prevent zebra mussel growth. Byron’s 

10 National Pollutant Discharge Elimination System (NPDES) permit, which is discussed in more 

11 detail in Section 3.5.1.3, limits the chemical concentrations in blowdown discharged to the Rock 

12 River.

13 3.1.4 Radioactive Waste Management Systems

14 As part of normal operations and as a result of equipment repairs and replacements due to 

15 normal maintenance activities, nuclear power plants routinely generate both radioactive and 

16 nonradioactive wastes. Nonradioactive wastes include hazardous and nonhazardous wastes. 

17 There is also a class of waste, called mixed waste that is both radioactive and hazardous. The 

18 systems used to manage (i.e., treat, store, and dispose of) these wastes are described in this 

19 section. Waste minimization and pollution prevention measures commonly employed at nuclear 

20 power plants are also discussed in this section.

21 All nuclear plants were licensed with the expectation that they would release radioactive 

22 material to both the air and water during normal operation. However, NRC regulations require 

23 that gaseous and liquid radioactive releases from nuclear power plants must meet radiation 

24 dose-based limits specified in Title 10 of Code of Federal Regulations (10 CFR) Part 20, and the 

25 as low as is reasonably achievable (ALARA) criteria in Appendix I to 10 CFR Part 50. 

26 Regulatory limits are placed on the radiation dose that members of the public can receive from 

27 radioactive effluents released by a nuclear power plant. All nuclear power plants use 

28 radioactive waste management systems to control and monitor radioactive wastes.

29 Byron uses liquid, gaseous, and solid waste processing systems to collect and process, as 

30 needed, radioactive materials produced as a by-product of plant operations. The liquid and 

31 gaseous radioactive effluents are processed to reduce the levels of radioactive material prior to 

32 discharge into the environment. This is to ensure that the dose to members of the public from 

33 radioactive effluents is reduced to levels that are ALARA in accordance with NRC’s regulations. 

34 The radioactive material removed from the effluents is converted into a solid form for eventual 

35 disposal at a licensed radioactive disposal facility.

36 Byron has a radiological environmental monitoring program (REMP) to assess the radiological 

37 impact, if any, to the public and the environment from radioactive effluents released during 

38 operations at Byron. The REMP measures the aquatic, terrestrial, and atmospheric 

39 environment for radioactivity, as well as the ambient radiation. In addition, the REMP measures 

40 background radiation (i.e., cosmic sources, global fallout, and naturally occurring radioactive 

41 material, including radon) (Teledyne 2013). 

42 Byron has an Offsite Dose Calculation Manual (ODCM) that contains the methods and 

43 parameters used to calculate offsite doses resulting from liquid and gaseous radioactive 

44 effluents. These methods are used to ensure that radioactive material discharges from the plant 

45 meet NRC and EPA regulatory dose standards. The ODCM also contains the requirements for 

46 the REMP (Teledyne 2013).
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1 3.1.4.1 Radioactive Liquid Waste Management

2 Radioactive liquids are processed as necessary by the liquid radwaste system (LRWS) for 

3 release to the environment into the Rock River via the circulating water blowdown line. The 

4 LRWS is designed so that liquid radwaste discharged from the site will have radioactive nuclide

5 concentrations well within the limits specified in 10 CFR 20 and 10 CFR 50, Appendix I. The 

6 layout of the LRWS consists of two main subsystems designed for collecting and processing the 

7 liquid waste: the steam generator blowdown subsystem and the non-blowdown subsystem. 

8 Each of the liquid radwaste processing streams terminates in a monitor tank, allowing each 

9 batch of liquid waste to be sampled and analyzed to ensure they are ALARA before being 

10 released. Based on the analysis of each sample, these wastes are either released under 

11 controlled conditions via the cooling water system or recycled through the same or a different 

12 subsystem for further processing. The data from the analysis is used to ensure that the release 

13 conforms to the controls specified in the ODCM. The ODCM’s controls are based on the 

14 concentration of radioactive material in the liquid effluent and the projected dose from the 

15 release.

16 Radioactive liquid waste is processed through a demineralizer system which removes soluble 

17 and suspended radioactive material using an ion exchange process and filtration prior to being 

18 released into the environment. Once the resin and filter media are expended, they are 

19 processed as waste for disposal.

20 The LRWS is shared by the two units; however, Unit 1 and Unit 2 have separate equipment and 

21 floor drain collection sump systems. The non-blowdown radwaste subsystem treats waste 

22 streams from the auxiliary building equipment drains, auxiliary building floor drains, chemical 

23 waste drains, regeneration waste drains, laundry drains, turbine building equipment and floor 

24 drains, and condensate polisher sump.

25 Radioactive liquid effluent paths are processed, monitored, and recycled or discharged via 

26 release tanks. Radioactivity analysis of the waste is performed prior to transferring the contents 

27 to the release tank. If the activity is below NRC regulatory release limits specified in the ODCM, 

28 the tank contents may be discharged to the Rock River via the circulating water blowdown line 

29 without further treatment. The blowdown line enters the Rock River approximately 61 m (200 ft)

30 downstream of the water intake structure to prevent mixing of the wastewater with the makeup 

31 water lines. Prior to where the release tank discharge line mixes with the blowdown line, a 

32 backup radiation detector monitors the discharged liquid. If abnormal radiation levels are 

33 detected, a valve closes automatically to prevent the release and an alarm annunciates in the 

34 Control Room.

35 A spent resin storage tank stores the used demineralizer resins. The resin is held in this tank 

36 for a period of time to allow for the decay of short-lived isotopes. The resin is periodically 

37 removed for disposal as radioactive solid waste. 

38 The use of these radioactive waste systems and the procedural requirements in the ODCM 

39 ensure that the dose from radioactive liquid effluents complies with NRC and EPA regulatory 

40 dose standards.

41 Dose estimates for members of the public are calculated based on radioactive liquid effluent 

42 release data and aquatic transport models. Exelon’s annual radiological effluent release report 

43 contains a detailed presentation of the radioactive liquid effluents released from Byron and the 

44 resultant calculated doses. The NRC staff reviewed 5 years of radioactive effluent release data: 

45 2008 through 2012 (Exelon 2009b, 2010c, 2011b, 2012c, 2013g). A 5-year period provides a 

46 data set that covers a broad range of activities that occur at a nuclear power plant such as 

47 refueling outages, routine operation, and maintenance activities that can affect the generation of 
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1 radioactive effluents. The NRC staff compared the data against NRC dose limits and looked for 

2 indication of adverse trends (i.e., increasing dose levels) over the period of 2008 through 2012. 

3 The following summarizes the calculated doses from radioactive liquid effluents released during 

2012: 4 

5 Unit 1 

6  The total-body dose to an offsite member of the public from Byron Unit 1 

radioactive liquid effluents was 8.03×10−2 7 millirem (mrem) 

(8.03×10−4 8 millisievert (mSv)), which is well below the 3 mrem (0.03 mSv) 

9 dose criterion in Appendix I to 10 CFR Part 50.

10  The organ dose (adult/GI-tract) to an offsite member of the public from Byron 

Unit 1 radioactive liquid effluents was 1.38×10−1 mrem (1.38×10−3 11 mSv), 

12 which is well below the 10 mrem (0.1 mSv) dose criterion in Appendix I to 

13 10 CFR Part 50.

14 Unit 2 

15  The total-body dose to an offsite member of the public from Byron Unit 2 

radioactive liquid effluents was 8.03×10−2 mrem (8.03×10−4 16 mSv), which is 

17 well below the 3 mrem (0.03 mSv) dose criterion in Appendix I to 10 CFR 

18 Part 50.

19  The organ dose (adult/GI-tract) to an offsite member of the public from Byron 

Unit 2 radioactive liquid effluents was 1.38×10−1 mrem (1.38×10−3 20 mSv), 

21 which is well below the 10 mrem (0.1 mSv) dose criterion in Appendix I to 

22 10 CFR Part 50.

23 The NRC staff’s review of Byron’s radioactive liquid effluent control program showed that 

24 radiation doses to members of the public were controlled within NRC’s and EPA’s radiation 

25 protection standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 40 CFR 

26 Part 190. No adverse trends were observed in the dose levels.

27 Routine plant refueling and maintenance activities currently performed will continue during the 

28 license renewal term. Based on the past performance of the radioactive waste system to 

29 maintain doses from radioactive liquid effluents to be ALARA, similar performance is expected 

30 during the license renewal term.

31 3.1.4.2 Radioactive Gaseous Waste Management

32 The gaseous waste processing system (GWPS) is designed to remove fission product gases 

33 from the reactor coolant and minimize the amount of radioactive material released into the 

34 environment. The GWPS is a shared system serving both units. It consists of two waste-gas 

35 compression packages, six gas decay tanks, and the associated piping, valves, and 

36 instrumentation. Gaseous wastes are generated from the following activities: gases removed 

37 from the reactor coolant and purging of the volume control tank prior to a cold shutdown of the 

38 reactor, displacing of cover gases caused by the accumulation of liquids in storage tanks, 

39 purging of some equipment, sampling and gas analyzer operation, and operating the boron 

40 recycle system. The reduction of the levels of radioactive material is accomplished by internal 

41 recirculation of the gases within piping systems and temporary storage in gas decay tanks. The 

42 recirculation of the gases and the temporary storage in the decay tanks allows time for 

43 radioactive decay to reduce the levels of radioactivity.

44 Gaseous radioactive wastes are released into the atmosphere, in a controlled and monitored 

45 manner, through two mixed-mode release point ventilation stacks. The radioactive gaseous 

46 waste sampling and analysis program specifications provided in the ODCM address the 
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1 gaseous release type, sampling frequency, minimum analysis frequency, type of activity 

2 analysis, and lower limit of detection (i.e., sensitivity) for the radiation monitor.

3 The use of these radioactive waste systems and the procedural requirements in the ODCM 

4 ensure that the dose from radioactive gaseous effluents complies with NRC and EPA regulatory 

5 dose standards.

6 Dose estimates for members of the public are calculated based on radioactive gaseous effluent 

7 release data and atmospheric transport models. Exelon’s annual radioactive material release 

8 report contains a detailed presentation of the radioactive gaseous effluents released from Byron 

9 and the resultant calculated doses. The NRC staff reviewed 5 years of radioactive effluent 

10 release data: 2008 through 2012. A 5-year period provides a data set that covers a broad 

11 range of activities that occur at a nuclear power plant such as refueling outages, nonrefueling 

12 outage years, routine operation, and maintenance activities that can affect the generation of 

13 radioactive effluents. The NRC staff compared the data against NRC dose limits and looked for 

14 indication of adverse trends (i.e., increasing dose levels) over the period of 2008 through 2012. 

15 The following summarizes the calculated doses from radioactive gaseous effluents released 

16 during 2012:

17 Unit 1

18  The air dose at the site boundary from gamma radiation in gaseous effluents 

from Byron Unit 1 was 4.36×10−4 millirad (mrad) (4.36×10−6 19 milligray (mGy), 

20 which is well below the 10 mrad (0.1 mGy) dose criterion in Appendix I to 

21 10 CFR Part 50.

22  The air dose at the site boundary from beta radiation in gaseous effluents 

from Byron Unit 1 was 3.07×10−3 mrad (3.07×10−5 23 mGy), which is well below 

24 the 20 mrad (0.2 mGy) dose criterion in Appendix I to 10 CFR Part 50.

25  The dose to an organ (child bone) from radioactive iodine, radioactive 

particulates, and carbon-14 from Byron Unit 1 was 4.06×10−1 26 mrem 

(4.06×10−3 27 mSv), which is well below the 15 mrem (0.15 mSv) dose criterion 

28 in Appendix I to 10 CFR Part 50.

29 Unit 2

30  The air dose at the site boundary from gamma radiation in gaseous effluents 

from Byron Unit 2 was 5.87×10−6 mrad (5.87×10−8 31 mGy), which is well below 

32 the 10 mrad (0.1 mGy) dose criterion in Appendix I to 10 CFR Part 50.

33  The air dose at the site boundary from beta radiation in gaseous effluents 

from Byron Unit 2 was 1.19×10−5 mrad (1.19×10−7 34 mGy), which is well below 

35 the 20 mrad (0.2 mGy) dose criterion in Appendix I to 10 CFR Part 50.

36  The dose to an organ (child bone) from radioactive iodine, radioactive 

particulates, and carbon-14 from Byron Unit 2 was 4.57×10−1 37 mrem 

(4.57×10−3 38 mSv), which is well below the 15 mrem (0.15 mSv) dose criterion 

39 in Appendix I to 10 CFR Part 50.

40 The NRC staff’s review of Byron’s radioactive gaseous effluent control program showed that 

41 radiation doses to members of the public were controlled within NRC’s and EPA’s radiation 

42 protection standards contained in Appendix I to 10 CFR Part 50, 10 CFR Part 20, and 40 CFR 

43 Part 190. No adverse trends were observed in the dose levels.

44 Routine plant refueling and maintenance activities currently performed will continue during the 

45 license renewal term. Based on the past performance of the radioactive waste system to 
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1 maintain doses from radioactive gaseous effluents to be ALARA, similar performance is 

2 expected during the license renewal term.

3 3.1.4.3 Radioactive Solid Waste Management

4 Solid low-level radioactive waste (LLW) is generated by the removal of radioactive material from 

5 liquid waste streams, filtration of gaseous effluents, and removal of contaminated material from 

6 various reactor areas. The waste is divided into two categories: dry active waste (DAW) and 

7 wet active waste (WAW). The solid waste system collects, processes, packages, and provides 

8 temporary storage for WAW prior to offsite shipment and burial, in accordance with NRC 

9 regulations in 10 CFR Parts 61 and 71. Transportation of the radioactive solid waste is 

10 governed by the U.S. Department of Transportation (DOT) regulations in 49 CFR 171 to 178. 

11 The solid waste system also receives, decontaminates, compacts, and provides temporary 

12 storage for DAW prior to offsite shipment and burial.

13 Types of waste handled by this system include expended deep bed demineralizer resins, 

14 disposable cartridge filter elements, DAW (such as air filters, miscellaneous paper, rags from 

15 contaminated areas and contaminated clothing, tools, and equipment parts), and solid 

16 laboratory wastes. Drums are used for packaging both WAW and DAW. Byron has a 

17 drumming area where two remotely operated cranes are used to transport and position the 

18 drums while in storage, as well as transport them to trucks for offsite disposal.

19 Routine plant operation, refueling outages, and maintenance activities that generate radioactive 

20 solid waste will continue during the license renewal term. Radioactive solid waste is expected 

21 to be generated and shipped off site for disposal during the license renewal term.

22 3.1.4.4 Radioactive Waste Storage

23 Low-level radioactive waste is stored temporarily on site in restricted areas until it can be 

24 shipped off site for disposal at a licensed LLW disposal facility.

25 Byron stores its spent nuclear fuel in a spent fuel pool and also maintains an independent spent 

26 fuel storage installation (ISFSI) on site. The ISFSI is used to safely store spent fuel in licensed 

27 and approved dry cask storage containers on site. The installation and monitoring of this facility 

28 is governed by NRC requirements in 10 CFR Part 72, “Licensing requirements for the 

29 independent storage of spent nuclear fuel, high-level radioactive waste, and reactor-related 

30 Greater than class C waste.” The Byron ISFSI would remain in place until the U.S. Department 

31 of Energy (DOE) takes possession of the spent fuel and removes it from the site for permanent 

32 disposal or processing. Expansion of the onsite spent fuel storage capacity may be required 

33 during the license renewal term. The impacts associated with this expansion would be 

34 assessed under the 10 CFR Part 72 license process separate from that of the Byron operating 

35 units. The Byron ISFSI is located within the existing protected area boundary. Spent fuel 

36 transfers to the ISFSI began in September 2010 when fuel from the spent fuel pool was placed 

37 in six casks and transferred to the ISFSI outdoor storage pad area and eight casks were added 

38 in 2012 (Teledyne 2013).

39 3.1.4.5 Radiological Environmental Monitoring Program

40 Exelon conducts a REMP to assess the radiological impact, if any, to the public and the 

41 environment from the operations at Byron. 

42 The REMP measures the aquatic, terrestrial, and atmospheric environment for radioactivity, as 

43 well as the ambient radiation by sampling air, water, milk, foods, soil, fish, and shoreline 

44 sediment. In addition, the REMP measures background radiation (i.e., cosmic sources, global 

45 fallout, and naturally occurring radioactive material, including radon). The radiation detection 
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3-14

1 devices and analysis methods used to determine the radioactivity in environmental samples are 

2 very sensitive to small amounts of radioactivity.

3 In addition to the REMP, Byron has an onsite ground water protection program designed to 

4 monitor the onsite plant environment for detection of leaks from plant systems and pipes 

5 containing radioactive liquid (Exelon 2013a). Information on the ground water protection 

6 program is contained in Section 3.5.2 of this document.

7 The NRC staff reviewed 5 years of annual radiological environmental monitoring data: 2008 

8 through 2012 (Teledyne 2009, 2010, 2011, 2012, 2013). A 5-year period provides a data set 

9 that covers a broad range of activities that occur at a nuclear power plant such as refueling 

10 outages, routine operation, and maintenance activities that can affect the generation and 

11 release of radioactive effluents into the environment. The NRC staff looked for indication of 

12 adverse trends (i.e., buildup of radioactivity levels) over the period of 2008 through 2012.

13 The NRC staff’s review of Exelon’s data showed no indication of an adverse trend in 

14 radioactivity levels in the environment. The data showed that there was no measurable impact 

15 to the environment from operations at Byron.

16 3.1.5 Nonradioactive Waste Management Systems

17 Like any other industrial facility, nuclear power plants generate wastes that are not 

18 contaminated with either radionuclides or hazardous chemicals. These wastes include trash, 

19 paper, wood, and sewage.

20 Byron has a nonradioactive waste management program to handle its nonradioactive hazardous 

21 and nonhazardous wastes. The waste is collected in central collection areas within the plant 

22 site and managed in accordance with Exelon’s procedures. The materials are received in 

23 various forms and packaged to meet regulatory requirements prior to final disposition at an 

24 offsite facility licensed to receive and manage the waste. Listed below is a summary of the 

25 types of waste materials generated and managed at Byron.

26  Byron is registered as a small-quantity hazardous waste generator, however, 

27 hazardous wastes are managed according to large-quantity generator 

28 standards. The amount of hazardous wastes generated are only a small 

29 percentage of the total wastes generated; consisting of paints and 

30 paint-related materials, spent and off-specification and shelf-life expired 

31 chemicals, laboratory chemical wastes, and occasional project-specific 

32 wastes. Byron has contracts in place to transfer hazardous waste to licensed 

33 offsite treatment and disposal facilities.

34  Byron’s nonhazardous wastes include potentially infectious medical waste 

35 (PIMW), used oil, grease, antifreeze, adhesives, and other petroleum-based 

36 liquids. PIMW is generated at a health facility on site and can include used 

37 and unused hypodermic needles and syringes, as well as items contaminated 

38 with human blood. PIMW is considered a unique special waste category in 

39 Illinois and transportation and disposal of this waste is regulated under 

40 35 Illinois Administrative Code (IAC) 1420.104 (a).

41  Universal wastes, such as batteries and mercury-containing lamps.

42  General plant trash is collected in dumpsters and transported to a 

43 state-licensed regional landfill permitted to accept solid wastes. General 

44 trash typically consists of garbage, paper, plastic, packing materials, leather, 

45 rubber, glass, soft drink and food cans, dead animals and fish, floor 

46 sweepings, ashes, wood, textiles, and scrap metal.
Affected Environment

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1 Exelon operates a sewage treatment package plant onsite. Effluent discharge is regulated 

2 under NPDES permit IL0048313. If the treatment plant is out of service, Exelon is authorized to 

3 transfer raw sewage up to 18,000 gallons per day (68,000 L/d) to the City of Oregon wastewater

4 collection system for treatment. This effluent discharge is regulated under the town’s NPDES 

5 permit IL0020184 (Exelon 2003).

6 3.1.6 Utility and Transportation Infrastructure

7 Existing utility and transportation infrastructure characteristics for Byron are briefly described in 

8 the following subsections.

9 3.1.6.1 Electricity

10 Byron receives offsite electrical power, as needed, from four different independent sources, via 

11 two separate power circuits from the 345-kV switchyard (Exelon 2013a). Each of these power 

12 circuits has its own separate ROW with independent transmission line structures. Byron also 

13 has two emergency diesel generators per unit designed to supply electrical power to key plant 

14 components when normal offsite power sources are not available (Exelon 2013d).

15 3.1.6.2 Fuel

16 Fuel is supplied to each diesel via the Fuel Oil System, which contains various tanks and fuel 

17 transfer pumps that provide fuel to each engine for a minimum of 7 days of operation without 

18 offsite support (Exelon 2013d). Byron’s Fuel Oil System consists of four 25,000-gallon (gal) 

19 diesel oil storage tanks dedicated to Unit 1 and two 50,000-gal storage tanks dedicated to Unit 2 

20 (Exelon 2013d).

21 3.1.6.3 Water

22 Systems designed to provide cooling water at Byron are described in Section 3.1.3. In addition 

23 to water needed for cooling, Byron requires water for sanitary purposes and for everyday use by 

24 personnel (e.g., drinking, showering, cleaning, laundry, toilets, and eyewashes). Byron draws 

25 potable water from the Cambrian-Ordovician Ironton-Galesville and Mt. Simon aquifers using 

26 two onsite groundwater wells, which also supply water to the demineralizer system 

27 (Exelon 2013a). As discussed in Section 3.1.5, Exelon operates an on-site sewage treatment 

28 package plant. Exelon is also authorized to transfer raw sewage to the City of Oregon 

29 wastewater collection system for treatment in the city’s sanitary wastewater treatment plant.

30 3.1.6.4 Transportation Systems

31 Byron has extensive paved surfaces, including parking lots and roads connecting power plant 

32 infrastructure. Direct access to the site is via German Church Road (County Highway 2), which 

33 runs northeast-southwest (Exelon 2013a). Section 3.10.6 describes roadway access and other 

34 local transportation systems in more detail. The Canadian Pacific Railway provides a railroad 

35 spur to the Byron site (Exelon 2013a).

36 3.1.6.5 Power Transmission Systems

37 Transmission lines that are with the scope of the NRC’s license renewal review are limited to 

38 those transmission lines that connect the nuclear plant to the substation where electricity is fed 

39 into the regional distribution system and transmission lines that supply power to the nuclear 

40 plant from the grid (NRC 2013a). Byron’s main power transformers are connected via 

41 intermediate, onsite transmission lines to the onsite 345-kV switchyard (Exelon 2013a).

42 Commonwealth Edison Company is the owner and operator of the power transmission line 

43 systems for Byron, which connect the site to the Mid-America Interpool Network regional 

44 transmission grid (Exelon 2013a). No separate transmission lines supply offsite power to Byron 
Affected Environment

3-16

1 from the grid (Exelon 2013a). Both switchyards and all the high-voltage lines would remain in 

2 service regardless of the proposed license renewal (ComEd 2013). 

3 3.1.7 Nuclear Power Plant Operations and Maintenance

4 Maintenance activities conducted at Byron include inspection, testing, and surveillance to 

5 maintain the current licensing basis (CLB) of the facility and to ensure compliance with 

6 environmental and safety requirements. Various programs and activities currently exist at Byron 

7 to maintain, inspect, test, and monitor the performance of facility equipment. These 

8 maintenance activities include inspection requirements for reactor vessel materials, boiler and 

9 pressure vessel inservice inspection and testing, and maintenance of water chemistry.

10 Additional programs include those carried out to meet technical specification surveillance 

11 requirements, those implemented in response to the NRC generic communications, and various 

12 periodic maintenance, testing, and inspection procedures (Exelon 2013a). Byron must 

13 periodically discontinue the production of electricity for outages supporting refueling, periodic 

14 inservice inspection, and testing and maintenance activities. The Byron units are on staggered 

15 18-month refueling cycles (Exelon 2013a).

16 3.2 Land Use and Visual Resources

17 3.2.1 Land Use

18 The Byron site is located in Ogle County in northern Illinois, approximately 3.7 mi (6.0 km) 

19 southwest of the City of Byron. Ogle County is the 17th largest county in Illinois and covers 

763 square miles (mi2

) (1,976 square kilometers (km2 20 )). Ogle County is located within the Rock 

21 River Hill Country subsection in the Till Plains section of the Central Lowland physiographic 

22 province (IDNR 2001).

23 The most common land use within Ogle County is agriculture (89 percent), which includes 

24 farmsteads, farm buildings, pasture, grazing lands, timberlands, grasslands, and other rural 

25 open space uses. The major crops grown in Ogle County are corn and soybeans. Wheat, oats, 

26 and hay are also grown (Exelon 2013a). Livestock raised in Ogle County include cattle and 

27 hogs. Remaining land uses include municipalities (4.5 percent), rural settlements (1.5 percent), 

28 residential (1.0 percent), and state parks/forested land (1.0 percent) (Exelon 2013a; Ogle 

29 County 2012). Population growth in Ogle County has been minimal over the past decade 

30 (Exelon 2013a). The municipalities (the largest of which are Rochelle, Oregon, and Byron) 

31 account for only 4.5 percent of land use in Ogle County, although 57 percent of the county 

32 population resides within these areas (Exelon 2013a).

33 The Ogle County Illinois Comprehensive Plan 2012 Update (Ogle County 2012) is the County’s 

34 land-use plan, and its goal is to:

35 [establish] an identifiable destination that allows both the governing body and

36 private interests to plan and budget with an idea as to the direction the County 

37 may move in the future, [and to] ensure that future growth is not only anticipated, 

38 but planned for.

39 In addition to this plan, Ogle County continues to implement its zoning and subdivision 

40 ordinances, greenways and trails plan, special flood hazards ordinance, comprehensive 

41 stormwater management ordinance, and municipality comprehensive land use plans 

42 (Exelon 2013a).

43 The Ogle County Greenways and Trails Plan (Sheaffer 2003) outlines the County’s land use 

44 goals for green infrastructure. Green infrastructure and greenways are defined in this plan as 
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1 recreational paths and trails, ecologically significant natural corridors, scenic and historic routes, 

2 networks of natural land forms (such as valleys and ridges), and urban waterfronts. The goals 

3 of the plan include development and conservation of greenways that contain multiple resources 

4 (particularly riparian areas), the protection of floodplains, the stabilization of native vegetation 

5 through the introduction of fragile soils, and the preservation of biodiversity and historic and 

6 cultural resources. 

7 In Ogle County, one of the most important natural areas is the Lowden-Miller State Forest near 

8 the City of Oregon (IDNR undated). The forest is adjacent to Castle Rock State Park, which is 

9 named for a unique sandstone bluff on the Rock River. Combined, these two areas cover 

10 approximately 4,225 ac (1,710 ha). These areas contain important natural habitat and are 

11 home to more breeding pairs of forest bird species than any other part of Illinois (IDNR 2001). 

12 These parks and their terrestrial habitats are discussed further in Section 3.6. 

13 Because Exelon’s ER (Exelon 2013a) looked at land use within a 5-mi (8-km) radius of the 

14 Byron site, NRC staff used this radius during its review. Land use within this radius is primarily 

15 agricultural. Some residential land use is centered on the cities of Byron and Oregon, both of 

16 which are within 5 mi (8 km) of the Byron site, and the remaining areas are primarily rural. 

17 Within 5 mi (8 km) of Byron are eight privately owned recreational areas, one county park, and 

18 one state park. The Lowden Memorial State Park is 3.5 mi (5.6 km) to the southwest of the 

19 Bryon site and occupies 207 ac (84 ha). Weld Memorial Park, owned by Ogle County, is 3 mi 

20 (4.8 km) northeast and occupies 35 ac (14 ha). These parks offer such recreational activities to 

21 the public as camping, picnicking, hiking, fishing, and boating on the Rock River.

22 The Byron Salvage Yard Superfund Site lies beyond the northwest boundary of the main Byron 

23 site. The superfund site consists of two separate land parcels: the Byron Salvage Yard and 

24 Dirk’s Farm (Exelon 2013a). Dirk’s Farm was purchased by Exelon as part of Byron’s 

25 circulating water pipeline ROW. The Byron Salvage Yard is not owned by Exelon. The 

26 automotive salvage yard portion of the Byron Salvage Yard was used as a dump for a variety of 

27 waste and debris. A contamination investigation and subsequent remediation began after 

28 several cattle deaths from cyanide-contaminated water occurred on Dirk’s Farm in 1975 

29 (EPA 2003). All soil and groundwater remedial actions are now completed on both sites and 

30 groundwater monitoring plans remain in place (EPA 2003).

31 The Byron site occupies 1,782 ac (721 ha), which consists of the main site area, which occupies 

32 1,398 ac (566 ha), and the water intake and discharge pipeline corridor, which occupies 384 ac 

33 (155 ha) (Exelon 2013a). Figure 3–3 depicts the main site area, which is surrounded primarily 

34 by agricultural fields. The power block and support facilities (buildings, switchyard, parking lots, 

35 and roads) occupy approximately 154 ac (62 ha), or 9 percent of the main site area. The plant 

36 exclusion area is located entirely within the main site area boundary and all activities occurring 

37 within the exclusion area are controlled by Exelon. Exelon operates an ISFSI within the site 

38 boundary. The Byron site is bounded by County Highway 2 (German Church Road), Deer Path 

39 Road, and Razorville Road. County Highway 2 provides access to the Byron site from 

40 highways State Route 72 and State Route 64.

41 The pipeline corridor extends west of the main site area approximately 2 mi (3.2 km) to the Rock 

42 River. The Rock River creates the furthest western boundary of the Byron site. The pipeline 

43 corridor is surrounded on- and off-site by primarily wooded lands (Exelon 2013a). Byron’s 

44 circulating water makeup intake structure is located at Rock River RM 115 (RKm 185), 

45 approximately 5 mi (8 km) downstream of the Byron, Illinois, U.S. Geological Survey (USGS) 

46 gaging station at Rock RM 120.3 (RKm 193.6). The Oregon Dam 4 mi (6.4 km) downstream 

47 creates the pool from which Byron draws its circulating water makeup and discharges its 

48 blowdown to and controls the water level at the intake.
Affected Environment

3-18

1 Approximately 538 ac (218 ha) of the Byron site was disturbed during the construction of the 

2 Byron facilities (30 percent) (Exelon 2013b). Forty-seven percent of the Byron site (840 ac) 

3 (340 ha) has been leased for agricultural use. This land is considered disturbed because most 

4 of it is tilled. The remaining 23 percent (404 ac (163 ha)) of Byron is undisturbed land. 

5 Regarding control of leased land within the Byron site, Exelon Generation generally retains an 

6 unrestricted right to enter, use, and dispose of the leased land for its business purposes and in 

7 the event of emergencies. Also, subleases are not permitted and leases typically restrict use of 

8 the leased land solely to a designated purpose, such as for farming and agricultural purposes, 

9 for cultivating crops, or for pastureland. Some leases may prohibit certain specific activities on 

10 the leased land, such as removing top soil, changing the original ground grade level, altering the 

11 natural water drainage pattern, and installing irrigation systems.

12 3.2.2 Visual Resources

13 The Byron site is situated at one of the highest points within a 5-mi (8-km) radius, at 869 ft 

14 (265 m) mean sea level. The topography surrounding the Byron facility gently slopes downward 

15 in nearly all directions, including west to the bank of the Rock River. Predominant features at 

16 the Byron site include the two reactor containment buildings, a turbine building, an auxiliary 

17 building, a fuel handling building, service buildings, training buildings, a steam generator storage 

18 building, a circulating water pumphouse, a circulating water blowdown discharge structure, 

19 two natural draft cooling towers, two mechanical draft cooling towers, electrical switchyard, and 

20 an ISFSI (Exelon 2013a).

21 The tallest structures on site are the two natural draft cooling towers at approximately 495 ft 

22 (151 m) above the ground (NRC 2006). A visible plume of condensation rising from the cooling 

23 towers can be seen when the cooling towers are operating. The height and visibility of the 

24 plume depends on weather conditions, such as temperature, humidity, and wind speed. Most 

25 cooling tower plumes at Byron occur between the cooling tower top (495 ft (151 m)) and a

26 height of 1,640 ft (500 m). Visible plumes may occasionally rise as high as 9,840 ft (3,000 m), 

27 although fewer than 10 percent of plumes are expected to ever exceed 3,280 ft (1,000 m). 

28 Visual impacts from natural draft cooling tower plumes at Byron are minimal in the summer and 

29 in cloudy weather. Impacts will be greatest on clear and calm winter days when plumes may 

30 reach higher elevations.

31 3.3 Meteorology, Air Quality, and Noise

32 3.3.1 Meteorology and Climatology

33 The Byron site is located near the center of Ogle County in northern Illinois, about 86 ft (139 km) 

34 west-northwest of Chicago. The site is located within Rock River Hill Country of the Till Plains 

35 Section of the Central Lowland Province in an agricultural area of gently rolling topography 

36 (ISGS 2013). The regional climate is continental with cold winters, warm summers, and 

37 frequent short fluctuations in temperature, humidity, cloudiness, and wind direction 

38 (NCDC 2013a). Weather systems create the wide variety of weather conditions that occur 

39 almost daily as a result of varying air masses and passing storm systems. Frequently, the polar 

40 jet stream is located near or over Illinois, especially in nonsummer months, which is associated 

41 with the creation and movement of low-pressure storm systems characterized by clouds, winds, 

42 and precipitation (NCDC 2013a). To some extent, the site is influenced by Lake Michigan, 

43 which is located as close as 76 mi (122 km) east of the site (NCDC 2013b).

44 The NRC staff obtained climatological data collected at the Rockford Airport National Weather 

45 Service (NWS) station, which is located about 13 mi (21 km) northeast of the site. Additionally, 

46 Byron maintains a meteorological facility that consists of a 250-ft (91-m) tower that is 
Affected Environment

3-19

1 instrumented at two levels for wind and ambient temperature measurements (Exelon 2013b). 

2 Data from these stations was used to characterize the region’s climate and are presented 

3 below.

4 For the 5-year period of 2008 to 2012, the average wind speed at the Rockford Airport NWS 

5 station was about 8.9 mph (4.0 m/s), with the highest at 10.3 mph (4.6 m/s) in spring and the 

6 lowest at 7.2 mph (3.2 m/s) in summer. Albeit not prominent, the prevailing wind direction was 

7 from the south (about 9.4 percent of the time). In general, southerly wind components are more 

8 frequent, followed by winds from northwesterly quadrant, from west through north. By season, 

9 wind blew from the south throughout the year, except from the west-northwest in winter. Wind 

10 speeds categorized as calm (less than 1.1 mph (0.5 m/s)) occurred about 14 percent of the 

11 time. The predominant wind direction at Byron for the 2008 to 2012 period was from the south 

12 with average annual wind speeds of 3.6 to 7.5 mph (1.6 to 3.4 m/s) (Exelon 2013b).

13 For the 62-year period, the annual average temperature at the Rockford Airport NWS station 

14 was 9.1 °C (48.3°F) (NCDC 2013b). January was the coldest month with a mean monthly 

15 average of −6.8°C (19.8°F), while July was the warmest with a mean monthly average of 

16 23.0 °C (73.4 °F). During the same period, the highest temperature of 40.6°C (105°F) was 

17 reached in July 2012, and the lowest of −32.8°C (−27 °F) in January 1982. In warmer months, 

18 daytime maximum temperatures exceed 32.2 °C (90 °F) about 15 days per year, with a peak of 

19 5.7 days in July. A daily minimum temperature at or below freezing is common during colder 

20 months (about 133 days per year), and subzero temperatures are recorded on about 11.5 days 

21 per year. The number of days with these temperatures peaked in January, about 29 days and 

22 5.5 days, respectively. Temperature trends from recent observations (2008 to 2012) at the 

23 Byron site (Exelon 2013b) are consistent with temperature observations at the Rockford Airport 

24 NWS station.

25 For the 30-year period, annual precipitation at the Rockford Airport NWS station averaged about 

26 36.2 in. (92.1 cm) (NCDC 2013b). On average, about 119 days per year have measurable 

27 precipitation (0.01 in. (0.025 cm) or higher). Summer is the wettest season, while winter is the 

28 driest season. Snow occurs as early as October and as late as April. On average, snowfalls 

29 are the highest in December, but peaks can occur in any of the three winter months. For the 

30 same period, the annual average snowfall was about 36.7 in. (93.2 cm), with the highest 

31 monthly snowfall of 30.2 in. (76.7 cm) in February 1994. Precipitation trends from recent 

32 observations (2008 to 2012) made at the Byron site (Exelon 2013b) are consistent with 

33 precipitation observations at the Rockford Airport NWS station.

34 Ogle County, where Byron is located, experiences severe weather events, such as floods, 

35 thunderstorm winds, and tornadoes. Other significant weather can be associated with these 

36 events; for example, lightning, hail, and high winds frequently occur with thunderstorms, and 

37 tornadoes can occur with thunderstorms. Since 1996, 10 floods, 49 hail events, and 

38 5 tornadoes have been reported in Ogle County (NCDC 2013d). The tornadoes occurring in 

Ogle County were relatively weak, mostly either F0 or EF1 on the Fujita scale.1 39

 

1 The original Fujita six-point scale (F0 to F5) was used to rate the intensity of a tornado based on the damage it inflicts to structures 

and vegetation from the lowest intensity, F0, to the highest, F5. In February 2007, the enhanced Fujita scale replaced the original 

Fujita scale. The enhanced Fujita scale still uses six categories of tornado intensity (EF0 to EF5), but the new scale more 

accurately matches wind speeds to the severity of damage caused by the tornado.
Affected Environment

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1 3.3.2 Air Quality

2 Under the Clean Air Act (CAA), the EPA has set primary and secondary National Ambient Air 

3 Quality Standards (NAAQS, 40 CFR 50) for six common criteria pollutants to protect sensitive 

4 populations and the environment. The NAAQS criteria pollutants include carbon monoxide 

5 (CO), lead (Pb), nitrogen dioxide (NO2), ozone (O3), sulfur dioxide (SO2), and particulate matter 

6 (PM). Particulate matter is further categorized by size—PM10 (aerodynamic diameter of 

7 10 micrometers or less) and PM2.5 (aerodynamic diameter of 2.5 micrometers or less).

8 The EPA designates areas of “attainment” and “nonattainment” with respect to the NAAQS. 

9 Areas that have insufficient data to determine designation status are denoted as 

10 “unclassifiable.” Areas that were once in nonattainment, but are now in attainment, are called 

11 “maintenance” areas; these areas are under a 10-year monitoring plan to maintain the 

12 attainment designation status. States have primary responsibility for ensuring attainment and 

13 maintenance of the NAAQS. Under section 110 of the CAA (42 U.S.C. 7410) and related 

14 provisions, states are to submit, for EPA approval, State Implementation Plans (SIPs) that 

15 provide for the timely attainment and maintenance of the NAAQS.

16 Air quality designations are generally made at the county level. For the purpose of planning and 

17 maintaining ambient air quality with respect to the NAAQS, EPA has developed Air Quality 

18 Control Regions (AQCRs). Air Quality Control Regions are intrastate or interstate areas that 

19 share a common airshed (40 CFR 81). The Byron site is located in Ogle County, Illinois; this 

20 county, along with the other four neighboring counties in Illinois and one county in Wisconsin, 

21 compose the Rockford (Illinois)-Janesville-Beloit (Wisconsin) Interstate AQCR (40 CFR 81.71). 

22 With regard to the NAAQS criteria pollutants, Ogle County is designated as an 

23 attainment/unclassifiable area for all criteria pollutants (40 CFR 81.314). Nearby designated 

24 nonattainment areas are McHenry County and Kane County for 8-hour ozone and PM2.5, which 

25 are about 30 mi (49 km) east-northeast of and 35 mi (56 km) east of the site, respectively. 

26 McHenry County and Kane County are also designated maintenance areas for the PM2.5 

27 standard (78 FR 60704).

28 Byron has a number of stationary emission sources permitted through its Federally Enforceable 

29 State Operating Permit (FESOP Permit No. 141820AAA); these include standby emergency 

30 diesel generators, auxiliary boilers, auxiliary feedwater pumps, essential service water makeup 

31 water pumps, a fire pump, and two natural draft and two mechanical draft cooling towers 

32 (IEPA 2002). A source is eligible for a FESOP (also known as “synthetic minor” air permit) if the 

33 potential to emit (PTE) from the source triggers CAA Permit Program requirements, but 

34 maximum actual emissions are below, or can be restricted to remain below, major source 

35 thresholds. As reported and submitted to the Illinois Environmental Protection Agency (IEPA), 

36 actual total emissions from all sources at Byron from 2008 to 2012 are presented in Table 3–1 

37 (Exelon 2009a, 2010a, 2011a, 2012a, 2013c). Annual emissions vary from year to year, but the 

38 highest emissions were reported in 2012. Byron has been in compliance with the requirements 

39 set forth in the air permit and there are no reported violations since October 1, 2011 

40 (EPA 2014a). 
Affected Environment

3-21

Table 3–1. Air Emission Estimates for Permitted Combustion Sources at Byron (a) 1 

NOx (t)(b) CO (t)(b) SOx (t)(b) PM2.5 (t)(b) PM10 (t)(b) VOC (t)(b) CO2e (t)(b)

2008 18.83 4.98 0.05 20.32 20.32 0.63 965

2009 24.51 6.50 0.04 20.83 20.83 0.72 1,257

2010 21.35 5.66 0.02 20.42 20.42 0.71 1,099

2011 21.30 5.65 0.02 21.13 21.13 0.67 1,101

2012 28.29 7.51 0.02 23.12 23.13 0.90 1,501

(a) NOx = nitrogen oxides; CO = carbon monoxide; SOx = sulfur oxides; PM2.5 = particulate matter with an 

aerodynamic diameter of 2.5 micrometers or less; PM10 = particulate matter with an aerodynamic diameter of 

10 micrometers or less; VOC = volatile organic compound; CO2e = carbon dioxide equivalent.

(b) To convert t (short tons) to MT (metric tons), multiply by 0.9072.

Sources: Exelon 2009a, 2010a, 2011a, 2012a, 2013c

2 On October 30, 2009, EPA published a rule for the mandatory reporting of greenhouse gases 

3 (GHGs) from sources that in general emit 25,000 MT or more of carbon dioxide equivalent 

(CO2e)2 4 per year in the United States (74 FR 56260). Most small facilities across all sectors of 

5 the economy fall below the 25,000-MT threshold and are not required to report GHG emissions 

6 to EPA. On June 3, 2010, EPA promulgated the Prevention of Significant Deterioration (PSD) 

and Title V GHG Tailoring Rule (75 FR 31514). Beginning January 2, 20113 7 , operating permits 

8 issued to major sources of GHG under the prevention of significant deterioration (PSD) or 

9 Title V Federal permit programs must contain provisions requiring the use of best available 

10 control technology (BACT) to limit the emissions of GHGs if those sources would be subject to 

11 PSD or Title V permitting requirements because of their non-GHG pollutant emission potentials 

12 and their estimated GHG emissions are at least 75,000 tons/yr of CO2 equivalents (CO2e). As 

13 discussed above, Byron is a synthetic minor source and as shown in Table 3–1, GHG emissions

14 from combustion sources at Byron are below the GHG Mandatory Reporting and Tailoring Rules 

15 thresholds; therefore, the NRC staff anticipates that Byron would be exempted from GHG 

16 emission limits. Additional GHG emission discussions are presented in Section 4.14 of this 

17 SEIS.

18 EPA promulgated the Regional Haze Rule to improve and protect visibility in national parks and 

19 wilderness areas from haze, which is caused by numerous, diverse sources located across a 

20 broad region (40 CFR 51.308–309). Specifically, 40 CFR 81 Subpart D lists mandatory Class I 

21 Federal Areas where visibility is an important value. The Regional Haze Rule requires states to 

develop SIPs to reduce visibility impairment at Class I Federal Areas. The nearest 4 22 Class I 

 

2 Carbon dioxide equivalents (CO2e) is a metric used to compare the emissions of GHG based on their global warming potential 

(GWP). GWP is a measure used to compare how much heat a GHG traps in the atmosphere. GWP is the total energy that a gas 

absorbs over a period of time, compared to carbon dioxide. Carbon dioxide equivalent is obtained by multiplying the amount of the 

GHG by the associated GWP. For example, the GWP of methane (CH4) is estimated to be 21; therefore, 1 t of methane emission 

is equivalent to 21 t of carbon dioxide emissions.

3 On June 23, 2014, the U.S. Supreme Court issued a decision that the EPA may not treat GHGs as an air pollutant for purposes of 

determining whether a source is a major source required to obtain a PSD or Title V permit, but could continue to require PSD and 

Title V permits, otherwise required based on emissions of conventional pollutants. In July 2014, the EPA issued a memorandum 

in response to the Supreme Court’s decision and acknowledged that, while the decision is pending judicial action, the EPA will no 

longer require PSD or Title V permits for GHG-emitting sources that are not sources subject to PSD or Title V permits based on 

emissions of conventional pollutants (nitrogen oxides, carbon monoxide, etc.) (EPA 2014c).

4 Rainbow Lake in Wisconsin is a Mandatory Federal Class I area where visibility is not an important air quality-related value. In 

1980 Rainbow Lake was excluded for purposes of visibility protection as a Class I area. Rainbow Lake is approximately 505 km 

(314 mi) north-northwest of Byron. 
Affected Environment

3-22

1 Federal area for visibility protection is the Seney Wilderness Area in Michigan (40 CFR 81.414), 

2 about 323 mi (520 km) north-northeast of the Byron site. The next nearest Class I area is the 

3 Mingo Wilderness Area in Missouri (40 CFR 81.416), which is located about 350 mi 563 km) 

4 south of the site. Considering the distances to the nearest Class I areas and the minor nature of 

5 air emissions from the site, there is little likelihood that activities at the Byron site could 

6 adversely affect air quality and air quality-related values (e.g., visibility or acid deposition) in any 

7 of the Class I areas. 

8 3.3.3 Noise

9 Any pressure variation that the human ear can detect is considered as sound, and noise is 

10 defined as unwanted sound. Sound is described in terms of amplitude (perceived as loudness) 

11 and frequency (perceived as pitch). Sound pressure levels are typically measured by using the 

12 logarithmic decibel scale. A-weighting (denoted by dBA) (ASA 1983, 1985) is widely used to 

13 account for human sensitivity to frequencies of sound (i.e., less sensitive to lower and higher 

14 frequencies and most sensitive to sounds between 1 and 5 kilohertz), which correlates well with 

15 a human’s subjective reaction to sound. Several sound descriptors have been developed to 

16 account for variations of sound with time. The equivalent continuous sound level (Leq) is a 

17 sound level that, if it were continuous during a specific time period, would contain the same total 

18 energy as a time-varying sound. Unless designated otherwise, all sound levels are 

19 instantaneous or Leq values measured over short time periods. In addition, human responses to 

20 noise differ depending on the time of the day (e.g., higher sensitivity to noise during nighttime 

21 hours because of lower background noise levels). The day-night average sound level (Ldn) is a 

22 single dBA value calculated from hourly Leq over a 24-hour period, with the addition of 10 dBA to 

23 sound levels from 10 p.m. to 7 a.m. to account for the greater sensitivity of most people to 

24 nighttime noise. Generally, a 3-dBA change over existing noise levels is considered to be a 

25 “just noticeable” difference, and a 10-dBA increase is subjectively perceived as a doubling in 

26 loudness and almost always causes an adverse community response (NWCC 2002). Table 3–2 

27 presents common sound sources and their respective noise levels.

28 Table 3–2. Common Noise Sources and Noise Levels

Source Noise Level (dBA)

Jet plane (at 100 ft distance) 130

Diesel truck (at 30 ft distance) 100

Food blender (at 3 ft distance) 90

Car (50 mph at 50 ft distance) 65

Conversation 55

Threshold of hearing 0

Sources: MMSHT 2008; SFU 1999

29 Nuclear power generation is an industrial process that can generate noise. Example noise 

30 sources at the Byron site include cooling towers, ventilation supply and exhaust fans, 

31 transformers, intake water pumps, transmission lines (corona discharge),relief valves, onsite 

32 vehicle traffic (commuter or delivery trucks), and shooting range activities (Exelon 2013c). 

33 Cooling towers and transformers are the primary contributing noise source as they are located 

34 outdoors and attributed to continuous plant operation.
Affected Environment

3-23

1 In addition to natural background noise (e.g., birds chipping, wind), noise sources around Byron 

2 include agricultural activities, local traffic on rural roads, recreational activities (e.g., motorsports 

3 park), nearby community activities and events, and infrequent aircraft overflights. Nearby 

4 noise sensitive receptors include several residences (mostly farmhouses) scattered around the 

5 site but are more than 0.6 mi (9 km) from primary noise sources at Byron and a church 

6 (Ebenezer Reformed Church), which is located about 1.0 mi (1.6 km) south of primary noise 

7 sources at Byron (Exelon 2013b). Noise modeling studies were made at four receptor locations 

8 within and around the site property line (Exelon 2013b). Predicted noise levels ranged between 

9 50 and 57 dBA Ldn, considering both the background and station contributions.

10 The activities at Byron would have to follow applicable Federal, State, or local guidelines and 

11 regulations on noise. Illinois has a noise regulation with allowable octave-band sound levels 

12 according to emitting and receiving land-use classification and time of day (IAC, Title 35: 

13 Environmental Protection, Subtitle H: Noise). The predicted noise levels from station 

14 operations are estimated to be below Illinois noise regulations (Exelon 2013b). Ogle County 

15 has noise ordinances with nuisance clauses against noise but has established no quantitative 

16 noise limits (Ogle County 2013). EPA uses a threshold level of 55 dBA Ldn to protect against 

17 excess noise during outdoor activities (EPA 1974). However, according to EPA this threshold 

18 does “not constitute a standard, specification, or regulation,” but was intended to provide a basis 

19 for State and local governments establishing noise standards (EPA 1974). The Department of 

20 Housing and Urban Development (HUD) has established noise assessment guidelines and finds 

21 that a noise level of 65 dBA Ldn or less is acceptable (HUD 2013).

22 3.4 Geologic Environment

23 This section describes the geologic environment of the Byron site and vicinity, including 

24 landforms, geology, soils, and seismic conditions.

25 3.4.1 Physiography and Geology

26 The Byron site is located in the Rock River Hill Country Subsection of the Till Plains Section of 

27 the Central Lowlands Physiographic Province (Leighton et al. 1948). This subsection is 

28 characterized by gently rolling, dissected uplands covered by thin layers of glacial drift deposits 

29 (geologic material deposited by glaciers or glacier associated streams and lakes). The 

30 southwest-trending Rock River Valley runs through the eastern portion of the subsection.

31 The bedrock surface controls the topography (Figure 3–6), which consists of well-developed 

32 drainages surrounded by subdued rolling hills and some sharp ridges containing local 

33 exposures of bedrock (USACE 2006). Relatively thin glacial drift deposits of sand, silt, and 

34 glacial till (poorly sorted nonstratified sand, silt, and gravel) overlie the bedrock surface. The 

35 power station was constructed in an area where the bedrock is close to the land surface, and 

36 the foundation of the generating facility was built into the bedrock. Depth to bedrock increases 

37 near the Rock River, which is underlain by alluvium (stream deposits). The underlying bedrock 

38 consists of 2,000 to 3,000 ft (610 to 910 m) of dolomite, sandstone, and shale rock. In turn, 

39 these rocks are underlain by granites and granodiorites to a great depth (CRA 2006).
Affected Environment

3-24

1 Figure 3–6. Site Topography

2 

3 Source: CRA 2006

4 3.4.2 Soils

5 At Byron, most of the soils have formed in glacial drift. The soils developed in geologic material 

6 that was directly deposited by the glacier (moraine deposits), or deposited by melting glacial ice 

7 water (outwash deposits), or by wind (loess and dune deposits), or deposited by the Rock River 

8 and local streams. Almost all of these soils contain a large amount of fine-grained silt-sized 
Affected Environment

3-25

1 material. Within the site boundary and along the pipeline that runs between the site and the 

2 river, most of the soils formed in moraine or outwash deposits. These soils are well-drained and 

3 are classified as silty loam or loam (USDA 2013).

4 3.4.3 Seismic Setting

5 The only reported injury from an earthquake that occurred in Illinois happened on April 12, 1883, 

6 when an old frame house was shaken down, resulting in slight injury to the inhabitants. 

7 A number of earthquakes (USGS 2013a, 2013b, 2013c) have originated within Illinois and 

8 include:

9  May 26, 1909, a large earthquake knocked over many chimneys in Aurora 

10 and swayed buildings in Chicago.

11  July 18, 1909, an earthquake knocked down chimneys in Petersburg.

12  August 14, 1965, a sharp local earthquake knocked down chimneys at Elco, 

13 Unity, Olive Branch, and Olmstead.

14  November 9, 1968, a magnitude 5.3 earthquake was felt over a large area.

15 Dozens of earthquakes originating outside Illinois have been felt inside the State without 

16 causing damage. These earthquakes originated in Missouri, Arkansas, Kansas, Nebraska, 

17 Tennessee, Indiana, Ohio, Michigan, Kentucky, and Canada. However, southern Illinois could 

18 experience major damage should a large-magnitude earthquake occur in the New Madrid 

19 Seismic Zone (located in southern Illinois and neighboring states) (MODNR 2013; USGS 2009). 

20 The site is located in northeast Illinois, which has a very small probability of experiencing 

21 damaging earthquakes (FEMA 2013; MAE Center 2009). The NRC requires every nuclear plant 

22 to be designed for site-specific ground motions that are appropriate for its location.

23 3.5 Water Resources

24 3.5.1 Surface Water Resources

25 This section describes surface water resources within and near Byron.

26 3.5.1.1 Surface Water Hydrology

27 The Rock River is the major surface water body in the region. It is located about 2 mi (3.2 km) 

28 to the west of Byron. The Rock River originates in southeastern Wisconsin and flows in a 

29 southwesterly direction into Illinois, ultimately discharging into the Mississippi River just 

30 downstream of Rock Island, Illinois (Figure 3–7). In total, the Rock River is approximately 

31 318 mi (512 km) long, with about 163 mi (262 km) of that length in Illinois (IEPA 2006; 

32 Sinclair 1996). There are eight major dams on the river’s main stem: Milan, Sterling, Rock 

33 Falls, Dixon, Oregon, Rockford, Rockton Spillway Lower, and Rockton Spillway Upper. These 

34 dams originally were built in the mid-1800s to early 1900s and are typically 10 to 15 ft (3 to 5 m) 

35 high (Knapp and Russell 2004). The dam at the City of Oregon, about 5 mi (8 km) downstream 

36 of Byron intake structure, forms the pool from which the station withdraws its makeup water and 

37 to which it discharges (Exelon 2013f; IEPA 2006).
Affected Environment

3-26

1 Figure 3–7. Rock River Basin in Illinois and Wisconsin

2 

3 Source: modified from Knapp and Russell 2004

4 The river screen house (intake structure) at the Byron site is located on the Rock River’s east 

5 bank at RM 115 (RKm 185) upstream from the river’s confluence with the Mississippi River 

6 (Exelon 2013b). The USGS maintains a stream gaging station on the Rock River at the City of 

7 Byron, Illinois (station 05440700). This gage is located approximately 5 mi (8 km) upstream of 

8 the river screen house. Another stream gaging station is located at Como, Illinois 

9 (station 05443500). This gage is located approximately 46 mi (74 km) downstream of the river 

10 screen house (see Figure 3–8) (USGS 2013d). Discharge data from the City of Byron gage 

11 dates back only to May 2000 (12 years of record). Therefore, it may not be most representative 
Affected Environment

3-27

1 of long-term river flow variability. The USGS gaging station at Como, Illinois, has a much longer 

2 reported record of river discharge (77 years). The mean annual river discharge measured at the 

USGS gage at Como, Illinois, for water years 1935 through 2012, is 6,033 cfs (170 m3 3 /s). The 

lowest average annual mean flow recorded over the period of record is 2,187 cfs (61.9 m3 4 /s). 

The mean 90 percent exceedance flow is 1,760 cfs (49.7 m3 5 /s) for the period of record. The 

6 90 percent exceedance flow is an indicator value of hydrologic drought in a watershed 

7 (USGS 2013d, 20113e).

8 Figure 3–8. The Rock River and USGS Stream Gaging Stations in the Vicinity of Byron

9 

10 Source: NRC Generated 

11 At the plant site, the only notable surface water body is an engineered retention pond called the 

12 Construction Runoff Pond. This pond is part of the plant’s storm drainage system and receives 

13 surface water runoff from the immediate vicinity of the plant. Prior to surface water reaching the 

14 pond, it passes through an oil-water separator. Discharges from this pond and all site storm 

15 water discharge is governed by the site’s Storm Water Pollution Prevention Plan 

16 (Exelon 2013a). Storm water collected in the Construction Runoff Pond either flows to the 

17 Unit 2 natural draft cooling tower basin where it becomes part of the circulating water system or 

18 it flows through NPDES Outfall 003 via drainage ditches located along German Church Road to 

19 the north of the main plant complex. From there the water ultimately flows to Woodland Creek 

20 and from Woodland Creek to the Rock River (Exelon 2013a, 2013b). Byron’s Storm Water 

21 Pollution Prevention Plan is implemented and maintained to comply with Special Condition 16 of 

22 the site’s Illinois-issued NPDES permit. The site’s NPDES permit is further discussed in 

23 Section 3.5.1.3.
Affected Environment

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1 3.5.1.2 Surface Water Use

2 As summarized in Section 3.1.3, Byron withdraws surface water from the Rock River to provide 

3 cooling water to the plant’s steam turbine condensers and, secondarily, to the plant’s 

4 nonessential service water (i.e., non-safety-related) system. Cooling tower blowdown and other 

5 permitted effluent streams are discharged back to the Rock River via the plant’s primary NPDES

6 outfall (Outfall 001) at a point located about 200 ft (61 m) downstream of the plant’s intake at the 

7 river screen house.

8 Exelon reports that Byron’s average makeup withdrawal rate has averaged about 36,750 gpm 

(81.9 cfs or 2.31 m3

/s), or about 52.9 million gallons per day (mgd) (200,000 m3 9 /day) 

10 (Exelon 2013a). NRC staff reviewed submittals by Exelon to the Illinois State Water Survey that 

11 recorded the volume of water intake and discharge from 2008 to 2012 (Table 3–3). Over that 

time period, Byron’s surface water withdrawals averaged 83.2 cfs (2.35 m3 12 /s or 53.8 mgd) and 

the plant discharge rate to the Rock River averaged 30.3 cfs (0.86 m3 13 /s or 19.6 mgd). The 

remaining 52.9 cfs (1.5 m3 14 /s or 34.2 mgd) was consumed by the plant and lost to the 

15 atmosphere by evaporation and drift. In contrast, the maximum (nominal) surface water 

withdrawal rate for Byron Units 1 and 2 is 45,200 gpm (101 cfs or 2.85 m3 16 /s). This is equivalent 

to 65 mgd (246,000 m3 17 /day) (Exelon 2013a).

18 Table 3–3. Annual Surface Water Withdrawals and Return Discharges to the Rock River, 

19 Byron

Year Withdrawals (mgy) mgd Discharges (mgy) mgd

2008 19,142.4 52.4 7,083.0 19.4

2009 20,239.5 55.5 7,272.9 19.9

2010 20,265.0 55.5 7,462.9 20.4

2011 18,966.8 52.0 7,003.1 19.2

2012 19,530.0 53.5 6,855.1 18.8

Average 19,628.7 53.8 7,135.4 19.6

Note: Reported values are rounded. To convert million gallons per year (mgy) to million cubic meters (m3), divide 

by 264.2.

Sources: Exelon 2008, 2009c, 2010d, 2011c, 2012e

20 Exelon limits the consumption of water from the Rock River by the Byron cooling systems 

21 (Exelon 2013b) to no more than 9 percent of total river flow when river flow is at or below 

679 cfs (19.2 m3 22 /s) (Exelon 2013b). This limit was established by an April 1977 construction 

23 permit (No. 15001) from the IDOT, Division of Water Resources. The construction permit also 

24 contains a requirement that limits Byron’s maximum makeup withdrawal rate from the river to 

125 cfs (3.5 m3 25 /s) (Exelon 2013a, 2013b). This operational limit is prescribed by Byron’s 

26 UFSAR (Exelon 2012d). A Byron plant operating procedure stipulates actions that plant 

27 personnel must take during low river flow. In summary, plant personnel monitor river flow using 

28 NWS and USGS data. When the river flow at the river screen house falls to 2,400 cfs 

(67.8 m3 29 /s) or less, daily monitoring of river flow is performed. If the calculated river flow falls to 

679 cfs (19.2 m3 30 /s), personnel then begin to calculate and monitor consumptive water use. If 

31 consumptive use exceeds 9 percent of river flow, the procedure dictates that circulating water 

32 makeup and blowdown flows are to be reduced until the consumption of river water falls below 
Affected Environment

3-29

1 9 percent of the flow in the river. If further action is needed, the procedure requires the power 

2 output of the reactor units to be reduced to further lower consumptive water use (Exelon 2013b).

3 3.5.1.3 Surface Water Quality and Effluents

4 The Illinois Pollution Control Board, a sister Agency to the Illinois EPA, promulgates water 

5 quality standards in Illinois. Two Sections of Title 35 of the IAC (35 IAC 302; 35 IAC 303) 

6 contain standards applicable to lakes and streams. Procedures for the use of water quality 

7 standards in setting NPDES permit limits are found in Section 309 (35 IAC 309). Designated 

8 uses prescribed by 35 IAC 303 are those uses specified in water quality standards for each 

9 lake, river, stream, and groundwater resource. In designating uses for a water body, the Illinois 

10 Pollution Control Board takes into consideration a water body’s value for public water supply; for 

11 propagation of fish, shellfish, and wildlife; and for recreational, agricultural, industrial, and 

12 navigational purposes (IEPA 2006).

13 The Rock River is designated as “general use water” by the Illinois Pollution Control Board. 

14 Water bodies designated as “general use water” must meet water quality standards protective of 

15 aquatic life, wildlife, agricultural use, secondary contact use, as well as most industrial uses and 

16 aesthetic quality (35 IAC 303). These standards pertain to pH, phosphorus, dissolved oxygen, 

17 radioactivity (gross beta, strontium-90, and radium-226 and -228), and various chemical 

18 constituents (metals and organic compounds), fecal coliform, and other toxic substances (as 

19 appropriate). Section 303(d) of the Federal Clean Water Act (CWA) requires the State of Illinois 

20 and other states to identify all “impaired” waters for which effluent limitations and pollution 

21 control activities are not sufficient to attain water quality standards (33 U.S.C. 1251 

22 Section 303d). The 303(d) list identifies stream segments that require the development of total 

23 maximum daily loads to assure future compliance with water quality standards. The IEPA has 

24 identified a 25.1-mi (~42-km) long segment of the Rock River that includes the Byron site as 

25 impaired, because it does not meet water quality standards for three contaminants due to 

26 contamination from polychlorinated biphenyls (PCBs), mercury, and ethanol attributable to 

27 various upstream sources (IEPA 2012). .

28 The water quality of surface water discharges is regulated by the IEPA via the NPDES program. 

29 NPDES permits are issued by the IEPA on a 5-year cycle. Byron is currently operating under 

30 NPDES Permit No. IL0048313, issued on January 24, 2011; the permit expires on 

31 December 31, 2015 (Exelon 2013b; IEPA 2011). It specifies discharge standards and 

32 monitoring requirements for chemical releases, water temperatures, and for storm water 

33 discharges through the plant’s outfalls to the Rock River and its tributaries. The outfalls are 

34 described in Table 3–4 and mapped in Figure 3–9.

35 The NPDES permit requires Exelon to monitor the flow rate, pH, suspended solids, and 

36 temperature of its cooling system blowdown discharge to the Rock River through its primary 

37 outfall (Outfall 001); other parameters include metals (zinc, iron, lead, copper, nickel, and 

38 chromium), hydrazine (an anticorrosive agent), oil and grease, 126 priority pollutants, and total 

39 residual chlorine/total residual oxidant (biocides agents). Sampling results are reported in 

40 monthly discharge monitoring reports submitted to the State. NRC staff reviewed discharge 

41 monitoring reports from 2008 through 2012 (Exelon 2013b) and found no “notice of violations” of 

42 NPDES permit requirements, unusual conditions of operations, or that effluent limitations were 

43 exceeded. As previously noted in Section 3.5.1.1, Exelon has prepared a storm water 

44 protection plan for Byron to manage its storm water discharges in compliance with Special 

45 Condition 16 of Byron’s NPDES permit.
Affected Environment

3-30

Table 3–4. National Pollutant Discharge Elimination System-Permitted Outfalls, Byron(a) 1 

Outfalls Average Flow 

Rate (mgd) Description

001 20.3

Cooling tower blowdown; nonessential and essential service water 

blowdown and strainer backwash; discharges to the Rock River via 

rip-rapped channel

A01 0.019 Demineralizer regenerant waste; discharges via Outfall 001

B01 0.008 Sewage treatment plant effluent; discharges via Outfall 001

C01 0.028 Wastewater treatment plant effluent; discharges via Outfall 001

D01 0.022 Radwaste treatment plant effluent; discharges via Outfall 001

E01 0.119 Storm water runoff basin; discharges via Outfall 001

F01 Intermittent Intake screen backwash; discharges to the Rock River via Outfall 001

002 Intermittent Stormwater runoff basin overflow to Woodland Creek

003 Intermittent East station area runoff to Woodland Creek

004 Intermittent West station area runoff to unnamed tributary to Rock River

Note: To convert million gallons per day (mgd) to million cubic meters (m3), divide by 264.2.

(a) Special Conditions 3 and 12 of the NPDES permit restrict temperature changes in the river and require Exelon to 

monitor the temperature of its discharge and provide the results in its monthly discharge monitoring report to the 

IEPA. When the river flow is less than 2,400 cfs (67.8 m3

/s) and/or the temperature differential between the main 

river temperature and the water quality standard is less than 3°F (1.7°C), compliance is to be demonstrated by 

calculations based on hourly measurements (averaged over a 24-hour period) of river flow, main river 

temperature, blowdown flow, and blowdown temperature values.

Outfalls A01, B01, C01, D01, E01, and F01 are internal monitoring stations for Outfall 001.

Source: IEPA 2011

2 An applicant (in this case Exelon) for a Federal license to conduct activities that may cause a 

3 discharge of regulated pollutants into navigable waters is required by Section 401 of the CWA to 

4 provide the licensing agency (in this case NRC) with water quality certification from the state (in 

5 this case the State of Illinois). This certification implies that discharges from the project or 

6 facility to be licensed will comply with CWA requirements and will not cause or contribute to a 

7 violation of state water quality standards. If the applicant has not received Section 401 

8 certification, the NRC cannot issue a renewed license unless that state has waived the 

9 requirement. The NRC recognizes that some NPDES-delegated states explicitly integrate their 

10 401 certification process with NPDES permit issuance. However, Byron’s NPDES permit does 

11 not explicitly convey water quality certification under CWA Section 401.

12 The Rock Island District of the U.S. Army Corps of Engineers (USACE) sent a letter to Exelon in 

13 October 2012 stating that no permit was required from USACE and that it had no objection to 

14 renewing the Section 401 certification for Byron (Exelon 2013b). Previously, by letter dated 

15 July 2, 2012, Exelon submitted an application to the IEPA Bureau of Water Pollution Control 

16 requesting certification that renewal of the plant’s NRC operating licenses would not violate 

17 state water quality standards (Exelon 2013b). 
Affected Environment

3-31

1 Figure 3–9. NPDES Discharge Locations

2 

3 Source: modified from Exelon 2013b
Affected Environment

3-32

1 In July 2013, the IEPA Division of Water Pollution Control responded to the Exelon request and 

2 sent a letter to the NRC regarding Byron’s 401 certification providing the 401 certification 

3 subject to inclusion of two conditions into the NRC license for Byron (IEPA 2013). 

4 In November 2014, NRC staff responded to IEPA, noting that since the two conditions are 

5 license requirements either because they are imposed as a matter of law or they state existing 

6 statutory provisions, no further NRC action is needed with respect to these two conditions. 

7 Specifically, (1) Exelon must obtain CWA Section 402 (NPDES) permits from the State in 

8 accordance with 33 U.S.C. § 1342, and (2) a 401 certification does not authorize activities that 

9 require authorizations under Section 404 of the CWA, 33 U.S.C. § 1344 (i.e., the permits for 

10 discharges of dredged or fill material, which are issued by the USACE) (NRC 2014b). 

11 To maintain the surface water intake system at the river screen house (see Section 3.1.3), 

12 Exelon conducts dredging to remove accumulated river sediment. The river bottom in the 

13 vicinity of the intake was engineered during plant construction to prevent the buildup of 

14 sediment and to maintain a connection to the cooler water in the main river channel. 

15 Specifically, a system of upstream wing dams and precast concrete turning vanes was 

16 constructed which directs cooling water toward the intakes while reducing scour and erosion of 

17 the opposite river bank (Exelon 2012d). While there is no prescribed frequency for dredging, 

18 divers are used to periodically examine intake area to assess the need to remove sediment. 

19 Dredging was performed at the river screen house in 2001 and again in 2007. Historically, both 

20 mechanical and hydraulic dredging has been conducted, with diver-assisted hydraulic dredging 

21 conducted most recently. Dredged river sediment is placed in a retention pond located in an 

22 upland area near the river screen house. Maintenance dredging at Byron is conducted via 

23 USACE Nationwide Permits in accordance with Section 10 of the Rivers and Harbors 

24 Appropriation Act of 1899 and Section 404 of the Clean Water Act (33 U.S.C. 403 Section 10 

25 and 33 U.S.C. 1251 Section 404). Permit coverage for maintenance dredging activities at Byron 

26 was reaffirmed in a letter from the USACE to Exelon in September 2012 (Exelon 2013b).

27 3.5.2 Groundwater Resources

28 This section describes the current groundwater resources within and near the Byron.

29 3.5.2.1 Site Description and Hydrogeology

30 There are four significant hydrogeologic units in the area of Byron. These are (in order of 

31 increasing depth) (1) the glacial drift, (2) the Galena-Platteville Dolomite aquifer, (3) the 

32 sandstone units of the Cambrian-Ordovician Aquifer System (including the St. Peter Sandstone 

33 and Ironton-Galesville Sandstone aquifers), and (4) the Mt. Simon Sandstone aquifer 

34 (Figure 3–10). Glacial drift occurs as a thin mantle across the site, with the depth to the 

35 underlying bedrock varying from zero to 12 ft (3.7 m). Groundwater in the glacial drift is 

36 recharged by local precipitation. Because it is thin and has low permeability, the glacial drift has 

37 not been developed as a source of groundwater on a large scale (CRA 2006; Exelon 2013b).

38 The Galena-Platteville Dolomite aquifer underlies the glacial drift. It ranges in thickness from 

39 100 to 225 ft (31 to 69 m). As with the glacial drift, recharge is by local precipitation. 

40 Groundwater in the glacial drift and in the Galena-Platteville Dolomite aquifer forms the local 

41 water table (CRA 2006; Kay et al. 1997). Groundwater movement in a water-table aquifer 

42 generally follows the local topography. Because Byron is situated on a topographic high, 

43 groundwater in the glacial drift and Galena-Platteville Dolomite aquifer flows from the site and 

44 discharges into the alluvium along the Rock River (Avery 1994). Groundwater in the 

45 Galena-Platteville Dolomite aquifer flows through the porous rock matrix and through fractures, 

46 joints, and solution openings. The aquifer provides modest yields for domestic use (Avery 1994; 

47 Exelon 2013b; IDNR 2002a; Kay et al. 1997).
Affected Environment

3-33

1 Figure 3–10. Generalized Hydrogeologic Column of Byron 

2 

3 Source: NRC Staff Generated

-... 

~ 

0 

100 

200 1--------i 

300 

400 

500 

! 600 J: 

... 

c. 

~ 

c 

700 

800 

900 

1,000 

1,100 

1,200 

Glacial Deposits 

Galena-Platteville Dolomite Aquifer 

Glenwood Formation 

St. Peter Sandstone Aquifer 

Prairie Du Chien Group 

Eminence Formation 

Potosi Dolomite 

Franconia Formation 

Ironton-Galesville Sandstone Aquifer 

Eau Clair Formation 

Mt. Simon Sandstone Aquifer 
Affected Environment

3-34

1 The Galena-Platteville Dolomite aquifer is underlain by the Glenwood Formation, which is 37 ft 

2 (11.3 m) thick and is made up of sandstone, dolomite, and shale beds. The Harmony Hill Shale 

3 forms the top of this formation (Kay et al. 1997). This shale does not readily transmit 

4 groundwater (due to low permeability) and is about 5 ft (1.5 m) thick. Along with other shales, 

5 within the Glenwood Formation, it forms a semiconfining layer above the underlying St. Peter 

6 Sandstone aquifer (Kay et al. 1997) (Figure 3–11).

7 The St. Peter Sandstone aquifer underlies the Glenwood Formation. It is about 420 ft (128 m) 

8 thick and is a regional aquifer (Kay et al. 1997). It is fully saturated and, because of the shale 

9 beds within the overlying Glenwood Formation, it is semiconfined. However, near the Rock 

10 River, the St. Peter Sandstone aquifer is unconfined (under water table conditions), as the 

11 overlying geologic units have been eroded away at that location (Kay et al. 1997). The 

12 groundwater recharge areas of the St. Peter Sandstone lie outside the Byron site area in 

13 northern Illinois and southern Wisconsin. However, locally it does receive some additional 

14 groundwater recharge by vertical leakage through the Glenwood Formation (CRA 2006). From 

15 the site, groundwater in the St. Peter Sandstone aquifer flows westward and discharges to the 

16 alluvium along the Rock River (Avery 1994; Kay et al. 1997). As a regional aquifer, the 

17 St. Peter Sandstone aquifer supplies small municipalities and domestic and industrial activities 

18 that have water needs of less than 200 gpm (757 liters per minute (L/min)) (Avery 1994; 

19 Kay et al. 1997).

20 The St. Peter Sandstone aquifer is underlain by the Prairie du Chien Group, Eminence 

21 Formation, Potosi Dolomite, and Franconia Formation. These units are comprised mainly of 

22 dolomite and shale with some sandstone. These units are an estimated 150 ft (46 m) thick 

23 (Visocky et al. 1985) and act as a “confining unit” between the St. Peter Sandstone aquifer and 

24 the underlying Ironton-Galesville Sandstone aquifer (Burch 2008).

25 The Ironton-Galesville Sandstone aquifer can be a productive source of groundwater and has 

26 an estimated thickness of about 150 ft (46 m). Together the St. Peter Sandstone aquifer and 

27 the Ironton-Galesville Sandstone aquifer make up the regional aquifer known as the 

28 Cambrian-Ordovician Aquifer System. This system is a significant source of water across 

29 northern Illinois (Burch 2008). The Eau Claire Formation underlies the Ironton-Galesville 

30 Sandstone aquifer. It has an estimated thickness of 200 ft (61 m). Because of its shale content, 

31 it is not considered to be an aquifer and acts as an aquitard (confining unit) (Sasman and 

32 Baker 1966; Visocky et al. 1985).

33 The Eau Claire Formation is underlain by the Mt. Simon Sandstone aquifer, which is a fine- to 

34 course-grained sandstone with gravel. The Mt. Simon Sandstone aquifer has an estimated 

35 thickness of about 1,500 to 2,000 ft (457 to 610 m) thick. It is capable of yielding moderate 

36 amounts of water (Sasman and Baker 1966; Visocky et al. 1985). Deeper sections of the 

37 Mt. Simon Sandstone aquifer (1,300 ft below sea level) are commonly too salty for municipal 

38 use (Sasman and Baker 1966).
3-35

Figure 3–11. Generalized East–West Hydrogeologic Cross Section 1 

2 

Source: modified from CRA 2006 3 
Affected Environment

3-36

1 3.5.2.2 Groundwater Use

2 Most of the water for municipal, domestic, and industrial use in the region is obtained from the 

3 St. Peter Sandstone aquifer. The nearest public water supply is the Northern Illinois University 

4 Lorado Taft field campus well field, located about 3.5 mi (5.6 km) to the southwest of the Byron. 

5 Here groundwater is withdrawn from two wells completed in the St. Peter Sandstone aquifer. 

6 The City of Byron, located about 4 mi (6.4 km) northwest of the station, uses groundwater from 

7 wells completed in the Ironton-Galesville Sandstone and Mt. Simon Sandstone aquifers 

8 (Exelon 2013b).

9 Two wells, W-1 and W-2, provide Byron with all its potable and demineralizer water supplies. 

10 The onsite wells extend to a depth of 1,500 ft (457 m) and produce water from the Ironton11 Galesville Sandstone and the Mt. Simon Sandstone aquifers. Each well has a maximum 

12 capacity of 800 gpm (3,028 L/min) and when both wells are in operation, they can supply Byron 

13 with water at 1,600 gpm (6,056 L/min). This high pumping capacity is available as an 

14 emergency backup water supply, in the event that essential cooling tower makeup water is not 

15 available from the Rock River. Exelon files annual reports documenting its groundwater

16 withdrawals with the Illinois State Water Survey (Exelon 2013b). Groundwater consumption 

17 varies depending on the activities conducted at the plant. The peak demand for groundwater is 

18 usually associated with refueling and maintenance activities. This activity could require up to 

19 470 gpm (1,779 L/min) (Exelon 2013b). However, this rate of groundwater consumption is of 

20 short duration. As a result, yearly groundwater use between 2008 and 2012 ranged from 

21 18 gpm to 43 gpm (68 to 163 L/min) and averaged 30 gpm (114 L/min) (Exelon 2009c, 2010d, 

22 2011c, 2012e; Teledyne 2008).

23 3.5.2.3 Groundwater Quality

24 All of the groundwater aquifers previously discussed can supply good quality water. However, 

25 northwest of the site, groundwater quality in the Galena-Platteville Dolomite aquifer has been 

26 contaminated and degraded by the Byron Salvage Yard Superfund Site. The Byron Salvage 

27 Yard Superfund Site occupies an area of about 180 ac (73 ha) near the northwest corner of the 

28 Byron site (IDPH 2005). The groundwater quality at the Byron Salvage Yard Superfund Site 

29 was not contaminated by any activities associated with Byron. During the 1960s and 1970s, the 

30 owner of the Byron Salvage Yard accepted electroplating wastes and other waste materials 

31 such as oil sludge, paint sludge, cutting wheels, solvents, and scrap metal. These materials 

32 were buried at the Byron Salvage Yard Superfund Site and in some areas dumped on the 

33 ground.

34 In 1976, the IEPA confirmed the presence of volatile organic compounds (VOCs) and heavy 

35 metals in the soil, surface water, and groundwater at the Byron Salvage Yard Superfund Site. 

36 Contaminants in groundwater include vinyl chloride, trichloroethylene, and cyanide 

37 (EPA 2013a). From the Byron Salvage Yard Superfund Site, two plumes of contamination are 

38 moving laterally within the Galena-Platteville aquifer. One plume moved northwest and 

39 one plume moved southwest (Kay et al. 1997). Both plumes are moving toward the Rock River. 

40 Cleanup and groundwater remediation activities at the Byron Salvage Yard Superfund Site have 

41 been ongoing since 1975. Groundwater monitoring will continue at the Byron Salvage Yard 

42 Superfund Site until contaminant levels fall below safe drinking water standards (EPA 2013a).

43 Beginning in 2006, Exelon conducted a groundwater investigation of the discharge (blowdown) 

44 pipeline that runs from the plant to the Rock River. As part of this investigation, multiple 

45 samples were obtained from the pipeline, from vacuum breaker vaults installed along the 

46 pipeline, from nearby residential wells, and from monitoring wells. Other than tritium, no 

47 radionuclides were or have since been discovered above their lower limit of laboratory 

48 detection. As reported in 2007, tritium was detected above the lower limit of detection in 
Affected Environment

3-37

1 four monitoring wells (AR-2, AR-3, AR-4, and AR-11). These wells are located close to 

2 three vacuum breaker vaults: VB-2, VB-3, and VB-4. The tritium concentrations in these wells 

3 ranged from 327 picocuries per liter (pCi/L) to 3,050 pCi/L. These concentrations were well 

4 below the EPA drinking water standard for tritium of 20,000 pCi/L. No tritium was detected in 

5 residential wells or found to be moving off site at detectible concentrations (CRA 2006).

6 Exelon continued to investigate tritium releases from the discharge (blowdown) pipeline in 

7 cooperation with the IEPA, the Illinois Attorney General’s Office, and the NRC. In March 2010, 

8 Exelon agreed to a consent order with the State of Illinois that was approved by the Circuit 

9 Court for the Fifteenth Judicial Circuit (Ogle County). The consent order required Exelon to 

10 prevent further releases of regulated wastewater to soil, surface water, or groundwater at Byron 

11 and to operate continuous monitoring systems in the vacuum breaker vaults along the pipeline. 

12 Exelon has complied with the consent order. The consent order was terminated in March 2011 

13 (Exelon 2013b), but Exelon continues to monitor the groundwater and vacuum breaker vaults.

14 By 2012, tritium was detected in only two wells adjacent to the pipeline (AR-4 and AR-11). 

15 Tritium levels in well AR-4 had declined from 3,050 pCi/L in 2007 to 830 pCi/L in 2012, and 

16 tritium levels in well AR-11 had declined from 1,820 pCi/L in 2007 to 994 pCi/L in 2012 

17 (Exelon 2013b; Teledyne 2008). Tritium concentrations in these two wells continue to be well 

18 below the EPA drinking water standard of 20,000 pCi/L.

19 Exelon routinely monitors the groundwater for radiological constituents and reports the results to 

20 the NRC. In addition, in 2007, the nuclear power industry began implementing its “Industry 

21 Ground Water Protection Initiative” (NEI 2007). The NRC staff has been monitoring 

22 implementation of this initiative at licensed nuclear reactor sites since 2008. Results from the 

23 “Industry Ground Water Protection Initiative” are reported annually to the NRC.

24 3.6 Terrestrial Resources

25 3.6.1 Byron Ecoregion

26 Beginning in the 1980s, the USGS, EPA, the Commission for Environmental Cooperation 

27 (CEC), and various other Federal agencies and interagency groups began delineating 

28 North American ecoregions in order to provide a common geographical framework to assess 

29 and manage the environment. Ecoregions are divided into Levels I through IV. Level I is the 

30 broadest category, while Level IV is the most specific. Ecoregions are delineated by many

31 factors to include location, climate, vegetation, hydrology, terrain, wildlife, and land use. The 

32 Byron site lies within the following Level I through IV ecoregions (EPA 2013b):

33  Level I: Eastern Temperate Forests,

34  Level II: Central USA Plains,

35  Level III: Central Corn Belt Plains, and

36  Level IV: Illinois/Indiana Prairies.

37 The Eastern Temperate Forests ecoregion covers the majority of the Eastern States and is 

38 characterized as having a moderate to mildly humid climate with dense and diverse forest cover 

39 consisting mostly of tall broadleaf, deciduous trees and needle-leaf conifers (CEC 2008). Within 

40 the Eastern Temperate Forests, the Central USA Plains is mostly glaciated to rolling plains, with 

41 some sand dunes and lake plains (Wiken et al. 2011). Large prairie communities and 

42 oak–hickory forests were native to this ecoregion, but have been largely replaced by agriculture. 

Within these plains, Byron lies in the Central Corn Belt Plains, which occupies 38,000 mi2 43

(98,000 km2 44 ) of land, primarily in northern Illinois and the northwestern corner of Indiana. 
Affected Environment

3-38

1 Gently rolling smooth plains, irregular plains, and shallow stream valleys characterize much of 

2 the area (USFS 1996). The native landscape of the ecoregion was composed of bluestem 

3 prairie communities and oak–hickory forests, but has mostly been replaced by corn and 

4 soybean agriculture. Common wildlife found in the region include white-tailed deer (Odocoileus 

5 virginianus), coyote (Canis latrans), bobcat (Lynx rufus), meadow vole (Microtus 

6 pennsylvanicus), Canada goose (Branta canadensis), mallard duck (Anas platyrhynchos), 

7 black-capped chickadee (Parus atricapillus), upland sandpiper (Bartramia longicauda), Illinois 

8 mud turtle (Kinosternon flavescens), and Illinois chorus frog (Pseudacris illinoensis) (Wiken 

9 et al. 2011). Agricultural lands are the predominant land cover in the ecoregion at 75.3 percent, 

10 followed by developed land (11.6 percent), and forests (9.3 percent). Although developed land 

11 is less prominent than agricultural land, from 1973 to 2000, the percent of developed land has 

12 increased 2.4 percent, while the percent of agricultural land and forested land has decreased 

13 (Karstensen et al. 2013d).

Byron site lies within the Upper Rock River watershed, which occupies 830 mi2 (2,100 km2 14 ) of 

15 the Rock River Hill Country Natural Division (IDNR 2002b). This area is characterized by rolling 

16 glaciated topography and a landscape historically dominated by prairie communities 

17 (59 percent), oak forests, dry upland forests, and floodplain forests. The Upper Rock River area 

18 land cover is now dominated by cropland (52.1 percent), grasslands (25.1 percent), forests 

19 (10.4 percent), open water (1.1 percent), and wetlands (1.5 percent) (IDNR 2002b). 

20 3.6.2 Byron Site and Vicinity

21 The Byron site occupies 1,782 ac (721 ha) immediately east of the Rock River. The main Byron 

22 site area, which is where the majority of the plant facilities are located, is approximately 

23 1,398 ac (566 ha) and is surrounded primarily by agricultural fields. Within the main site area, 

24 the power block and support facilities (buildings, switchyard, parking lots, and roads) occupy 

25 approximately 154 ac (62 ha). Approximately 840 ac (340 ha) are disturbed lands that are 

26 leased for agricultural uses, including croplands, pastures, and fallow fields. Forests, meadows, 

27 and grasslands occupy the undisturbed portions of the site, which encompass 404 ac (163 ha). 

28 The water intake and discharge pipeline and transmission corridor occupy the remaining 384 ac 

29 (155 ha) of the site. This corridor extends west from the main site area approximately 2 mi 

30 (3.2 km) to the Rock River and is surrounded by primarily wooded lands. (Exelon 2013b)

31 3.6.2.1 Summary of Past Byron Surveys and Reports

32 Commonwealth Edison Company conducted site surveys of the Byron site in the fall of 1972, 

33 and the winter, spring, and summer of 1973 as part of the construction permit application for 

34 Byron Units 1 and 2. Vegetation and wildlife in the transmission and pipeline corridor were 

35 surveyed in November 1973. These initial site surveys were used to determine baseline 

36 conditions of the terrestrial environment before construction. 

37 In 2006, while developing a biodiversity assessment and wildlife habitat management plan for 

38 the Byron site, Exelon staff conducted tours of the site with trained biologists (Starke and 

39 Cox 2011). Exelon staff recorded any vegetation, bird species, or other wildlife observed during 

40 these tours.

41 These surveys are the primary sources for describing the terrestrial resources at Byron. To 

42 supplement such surveys, the NRC staff conducted an environmental site visit and a desktop 

43 review of other natural resource databases and surveys within the vicinity of Byron. 
Affected Environment

3-39

1 3.6.2.2 Vegetation

2 Common Vegetation

3 Byron lies within the Upper Rock River Basin, which covers nearly 6,000 ac (2,428 ha) in 

4 northern Illinois and supports approximately 800 native plant species. Prior to the construction 

5 of the Byron facilities, 50 percent of the site was agricultural cropland. The northern half of the 

6 site was wooded with some cropland, and the southern half was mainly cropland. 

7 Approximately 35 percent of the site was grassland and fallow fields, consisting mainly of 

8 ragweed (Ambrosia artemisiifolia), alfalfa (Medicago sativa), and red clover (Trifolium pretense) 

9 in the fallow fields, and Kentucky bluegrass (Poa pratensis), timothy (Phleum pretense), and 

10 Canada bluegrass (Poa compressa) in the grasslands (Exelon 2013a). The remaining 

11 15 percent was forested and consisted primarily of oak (Quercus spp.) and hickory (Carya spp.) 

12 varieties. The transmission and pipeline corridor area was approximately 44 percent (212 ac 

13 (86 ha)) cultivated land (mostly cornfields), and approximately 39 percent (189 ac (76 ha)) was 

14 forested. The wooded and meadow areas of the Byron site have remained undisturbed since 

15 the property was purchased in the 1970s.

16 Construction of Byron disturbed approximately 538 ac (218 ha), or 30 percent of the existing 

17 Byron site. The majority of land on the Byron site is currently agricultural land, with about 

18 300 ac (121 ha) of wooded lands and 150 ac (61 ha) of meadow or grasslands. Currently, 47 

19 percent of the Byron site (840 ac (340 ha)) is leased for agricultural use. This land is 

20 considered disturbed because most of it is tilled. The remaining 23 percent (404 ac (163 ha)) of 

21 Byron is undisturbed land (Exelon 2013b).

22 Based on baseline surveys performed by ComEd (1981), Exelon concluded that the dominant 

23 tree species on the site are oak (Quercus spp.) and hickory (Carya spp.) varieties. Common 

24 oak varieties recorded during the 2006 tours of the Byron site include black oak (Q. velutina), 

25 jack oak (Q. ellipsoidalis), pin oak (Q. palustria), red oak (Q. rubra), and white oak (Q. alba). 

26 Hickory varieties recorded include mockernut hickory (C. tomentosa), shagbark hickory 

27 (C. ovate), and shellbark hickory (C. laciniosa). Other common tree assemblages found in both 

28 1973 and 2006 include American elm (Ulmus americana), black walnut (Juglans nigra), 

29 hackberry (Celtis occidentalis), and cottonwood (Populous deltoides). Understory plants include 

30 round-leaf dogwood (Cornus rugosa), northern prickly ash (Zanthoxylum americanum), and wild 

31 grape (Vitis spp.) (ComEd 1981; Starke and Cox 2011).

32 Several invasive species common to Illinois are found on the Byron site. Observed invasive 

33 species include bull thistle (Cirsium vulgare), chicory (Cichorium intybus), giant foxtail (Setaria 

34 faberii), wild carrot (Daucus carota), wild parsnip (Pastinaca sativa), and Osage-orange 

35 (Maclura pomifera) (CISEH 2009; Starke and Cox 2011).

36 Wetlands

37 Based on an examination of U.S. Fish and Wildlife Service (FWS) National Wetland Inventory 

38 maps, a small presence of wetlands exists on the Byron site. The only occurrence of wetlands 

39 on site is less than 5 ac (2 ha), or less than 0.3 percent of the Byron total site area. These 

40 freshwater forested/shrub wetlands occur on the north edge of the site’s western border, 

41 adjacent to the Rock River. FWS (2013d) classifies these wetlands as palustrine, which means 

42 that the nontidal wetlands occur in a floodplain and are dominated by trees, shrubs, emergent 

43 vegetation, mosses, or lichens. Other characteristics are that the total area of the wetlands 

44 does not exceed 8 ha (20 ac), the wetlands do not have an active wave-formed or bedrock 

45 shoreline, the wetlands have a depth less than 2 m (6.6 ft) at low water, and have a salinity of 

46 less than 0.5 parts per thousand. This wetland is also characterized as being seasonally 
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1 flooded and created or modified by a manmade barrier or dam, which obstructs the inflow or 

2 outflow of water.

3 Additional wetlands occur within the vicinity (5 mi (8 km)) of Byron, including more freshwater 

4 forested and shrub wetlands as well as freshwater emergent wetlands (FWS 2013d). These 

5 wetlands primarily occur along the Rock River.

6 Vegetation Management

7 Vegetation management at Byron is the responsibility of the Facilities Maintenance Department. 

8 Different vegetation management guidelines are followed based on the particular area of the 

9 Byron site. For example, the high-security areas both inside and outside the Protected Area 

10 around the facility are mowed to a height of 6 in. Outlying areas that are of less significance to 

11 plant security are treated to some degree with vegetation maintenance to allow for worker 

12 access, but are mowed only about twice a year. The undeveloped areas of the site are typically 

13 given vegetation maintenance only in response to special requests (Exelon 2013b).

14 State-Listed Vegetation

15 This section discusses plant species protected only by the State, and Section 3.8 discusses 

16 those species protected under the Endangered Species Act (ESA) alone or in combination with 

17 the State. As discussed in Section 3.1.6, Byron and the inscope transmission lines are located 

18 entirely within Ogle County. Table 3–5 identifies the 55 plant species that are considered 

19 threatened or endangered by the State of Illinois within Ogle County and Winnebago County. 

20 On the Byron site, no State-threatened or endangered species have been observed during the 

21 1973 baseline surveys or while developing the site’s wildlife habitat management plan 

22 (ComEd 1981; Starke and Cox 2011). 
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1 Table 3–5. State-Listed Plant Species in Ogle County

Scientific Name Common Name State of Illinois 

Status(a)

Amelanchier sanguinea shadbush SE

Arctostaphylos uva-ursi bearberry SE

Asclepias lanuginosa wooly milkweed SE

Aster furcatus forked aster ST

Besseya bullii kitten tails ST

Betula alleghaniensis yellow birch SE

Carex cryptolepis sedge SE

Carex echinata little prickly sedge SE

Carex woodii pretty sedge ST

Castilleja sessiliflora downy yellow painted cup SE

Ceanothus herbaceus redroot SE

Cornus canadensis bunchberry SE

Corydalis sempervirens pink corydalis SE

Cyclonaias tuberculata purple wartyback ST

Cypripedium acaule moccasin flower SE

Dichanthelium boreale northern panic grass SE

Equisetum pretense meadow horsetail ST

Equisetum sylvaticum horsetail SE

Filipendula rubra queen-of-the-prairie SE

Gymnocarpium dryopteris oak fern SE

Helianthus giganteus tall sunflower SE

Lathyrus ochroleucus pale vetchling ST

Lespedeza leptostachya prairie bush clover SE

Luzula acuminate hairy woodrush SE

Lycopodium clavatum running pine SE

Lycopodium dendroideum ground pine SE

Nothocalais cuspidata prairie dandelion SE

Phegopteris connectilis long beech fern SE

Sorbus Americana American mountain ash SE

Sullivantia sullivantii Sullivantia ST

Tomanthera auriculata ear-leafed foxglove ST
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Scientific Name Common Name State of Illinois 

Status(a)

Trientalis borealis star-flower SE

Woodsia ilvensis rusty woodsia SE

(a) SE = State-endangered; ST = State-threatened

Source: IDNR 2013

1 3.6.2.3 Wildlife

2 Common Wildlife

3 Byron is in the Upper Rock River Basin, which has a high terrestrial species diversity due to its 

4 extensive range of habitats and available vegetation (IDNR 2001). The Byron site provides 

5 several types of terrestrial habitats for birds, mammals, and other wildlife. Plant communities 

6 and wooded areas along the Rock River shoreline provide an important source of food and 

7 refuge for birds. The combination of food, protection, and other resources available make the 

8 Upper Rock River Basin and the Byron site an important habitat for many birds and wildlife. In 

9 addition, the area is part of the Mississippi flyway and an important stopover location for many 

10 migratory birds (Exelon 2013a; IDNR 2002b).

11 The baseline surveys at the Byron site identified 103 migratory and resident bird species on the 

12 site (ComEd 1981). The more recent 2006 wildlife observations indicate a total of 107 bird 

13 species (Starke and Cox 2011). Fourteen mammal species were originally identified in the 1973 

14 surveys, with an additional seven species added from more current observations. Only 

15 three reptile and amphibian species were observed in 1973, and, since the baseline surveys, 

16 seven more species have been added to that list. Table 3–6 describes the most common or 

17 abundant birds, mammals, reptiles, and amphibians on the Byron site.

18 As described in Section 3.2, several important natural areas occur within the vicinity of Byron. 

19 As described above, this area is part of the Mississippi flyway, used by migrating birds as 

20 important stopover points during long seasonal migrations (FWS 2013f). Species of diving and 

21 dabbling ducks, Canada geese, and particularly snow geese (Chen caerulescens) use corridors 

22 that cross north central Illinois in their migration. High-quality bird habitats within the region 

23 surrounding Byron include the Lowden–Miller State Forest and the adjacent Castle Rock State 

24 Park. The Audubon Society designates both of these areas as Important Bird Areas (IBAs). 

25 Combined, these two areas cover approximately 4,225 ac (1,710 ha) and provide one of the 

26 finest bird habitats in Illinois. This large, forested tract of land offers resident and migratory 

27 birds protection and is home to more breeding pairs of forest bird species than any other part of 

28 Illinois (IDNR 2001). Castle Rock State Park contains some of the most diverse terrestrial 

29 habitats in the Upper Rock River area, including ravine forest, upland forest, prairie, river 

30 creeks, and sandstone outcrops (IDNR 2002b). The most unique features of the park are mesic 

31 upland forest and sandstone cliffs, which provide habitat for relict boreal plants (IDNR 2002b).
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1 Table 3–6. Most Common or Abundant Wildlife on the Byron Site

Birds

Migratory Birds

fox sparrow

(Passerella iliaca)

slate-colored junco

(Junco hyemalis)

golden-crowned kinglet

(Regulus calendula)

white-throated sparrow

(Zonotrichia albicollis)

Resident Birds

American crow 

(Corvus brachyrhynchos)

cedar waxwing

(Bombycilla cedrorum) 

American goldfinch

(Spinus tristis)

robin

(Turdus migratorius)

Game Birds

American woodcock

(Philohela minor)

mourning dove

(Zenaidura macroura)

bobwhite quail

(Colinus virginianus)

ring-necked pheasant

(Phasianus colchicus)

gray partridge

(Perdix perdix)

Mammals

common opossum

(Didelphis marsupialis)

raccoon

(Procyon lotor)

deer mouse

(Peromyscus maniculatus)

wood mouse

(Peromyscus leucopus)

meadow vole

(Microtus pennsylvanicus)

Reptiles and Amphibians

alligator snapping turtle

(Macroclemys temminckii)

garter snake

(Thamnophis sirtalis)

American toad

(Bufo americanus)

red milk snake

(Lampropeltis triangulum syspila)

Bullfrog

(Rana catesbeiana)

smooth softshell turtle

(Apalone mutica)

Bullsnake

(Pituophis melanoleucus)

spring peeper

(Hyla crucifer)

eastern hognose snake

(Heterodon platyrhinos)

western chorus frog

(Pseudacris triseriata)

Sources: Exelon 2013a; Starke and Cox 2011
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1 State-Listed and Other Important Wildlife

2 This section discusses bird, mammal, and reptile species protected only by the State, the Bald 

3 and Golden Eagle Protection Act (BGEPA), and the Migratory Bird Treaty Act (MBTA). 

4 Section 3.8 discusses those species protected under the ESA alone or in combination with the 

5 State.

6 Birds

7 Table 3–7 identifies the four birds that are considered threatened or endangered by the State of 

8 Illinois within Ogle County.

9 Table 3–7. State-Listed Bird Species in Ogle County

Scientific Name Common Name State of Illinois Status

Birds

Ammodramus henslowii Henslow’s sparrow Threatened

Bartramia longicauda upland sandpiper Endangered

Haliaeetus leucocephalus bald eagle Threatened

Lanius ludovicianus loggerhead shrike Threatened

Source: IDNR 2013

10 With the exception of the bald eagle, none of the State-listed bird species presented in 

11 Table 3–7 have been observed on the Byron site during the 1973 baseline surveys or while 

12 developing the site’s wildlife habitat management plan (ComEd 1981; Exelon 2013a; Starke and 

13 Cox 2011).

14 Byron is located approximately 6 mi (10 km) northeast of the Castle Rock State Park and 

15 Lowden–Miller State Forest IBA (Exelon 2013b). The Lowden–Miller State Forest and Castle 

16 Rock State Park host a variety of rare breeding warblers and other song birds and host nesting 

17 populations of several bird species rarely found in Illinois, including the black-throated green 

18 warbler (Setophaga virens), the cerulean warbler (S. cerulea), the hooded warbler (S. citrina), 

19 the worm-eating warbler (Helmitheros vermivorum), the chestnut-sided warbler 

20 (S. pensylvanica), and the golden-winged warbler (Vermivora chrysoptera). The Audubon 

21 Society designated this area IBA because it meets the habitat criteria for both the State-listed 

22 threatened cerulean warbler and the blue-winged warbler (V. cyanoptera) (Audubon 2013).

23 Species Protected under the Bald and Golden Eagle Protection Act

24 The Bald and Golden Eagle Protection Act of 1940, as amended (16 U.S.C. § 668–668c) 

25 (BGEPA), prohibits anyone from taking bald or golden eagles (Aquila chrysaetos), including 

26 their nests or eggs, without a permit issued by the FWS. The Act and regulations define the 

27 word “take” to include the following: to pursue, shoot, shoot at, poison, wound, kill, capture, 

28 trap, collect, destroy, molest, or disturb (50 CFR 22.3). The word “disturb” means, among other 

29 things, to take action that causes (1) injury to an eagle, or (2) a decrease in its productivity or 

30 nest abandonment, by substantially interfering with breeding, feeding, or sheltering behavior 

31 (50 CFR 22.3).

32 Bald eagles have been observed along the banks of the Rock River near the Byron site, as well 

33 as other locations along the Rock River and its tributaries (eBird 2013; Exelon 2013a).
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1 Species Protected Under the Migratory Bird Treaty Act

2 The MBTA of 1918, as amended (16 U.S.C. §§ 703–712), is administered by the FWS. The Act 

3 prohibits anyone from taking native migratory birds, their eggs, feathers, or nests. MBTA 

4 regulations define “take” to mean to pursue, hunt, shoot, wound, kill, trap, capture, or collect, or 

5 any attempt to carry out those actions (50 CFR 10.12). However, take does not include habitat 

6 destruction or alteration. All Illinois State listed species shown in Table 3–7 are protected under 

7 the MBTA.

8 Mammals

9 Table 3–8 identifies the nine mammals that are considered threatened or endangered by the 

10 State of Illinois.

11 Table 3–8. State-Listed Mammal Species in Illinois

Scientific Name Common Name State of 

Illinois Status

Mammals

Canis lupus gray/timber wolf Threatened

Corynorhinus rafinesquii Rafinesque’s big-eared bat Endangered

Myotis austroriparius southeastern myotis Endangered

Myotis grisescens gray bat Endangered

Myotis sodalist Indiana bat Endangered

Neotoma floridana eastern woodrat Endangered

Ochrotomys nuttali golden mouse Threatened

Oryzomys palustris rice rat Threatened

Spermophilus franklinii Franklin’s ground squirrel Threatened

Source: IESPB 2011

12 None of the State-listed mammals reported in Table 3–8 above have been reported on or near 

13 the Byron site (Exelon 2013a; Starke and Cox 2011).

14 Reptiles and Amphibians 

15 Table 3–9 identifies the two reptiles and one amphibian that are considered threatened or 

16 endangered by the State of Illinois.
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1 Table 3–9. State-Listed Reptile and Amphibian Species in Ogle County

Scientific Name

Common Name 

State-Listed Reptile 

and Amphibian Species 

in Ogle County

State of Illinois Status

Reptiles

Equisetum pretense Blanding’s turtle Threatened

Hemidactylium scutatum four-toed salamander Threatened

Heterodon nasicus western hognose snake Threatened

Source: IDNR 2013

2 None of the State-listed species reported in Table 3–9 above have been reported on or near the 

3 Byron site during the 1973 baseline surveys or while developing the site’s wildlife habitat 

4 management plan (Exelon 2013a; Starke and Cox 2011).

5 3.6.3 Transmission Line Corridors

6 Section 3.1.6.5 describes the inscope transmission lines, which are limited to those 

7 transmission lines that connect the nuclear plant to the switchyard where electricity is fed in to 

8 the regional distribution system (NRC 2013a). For Byron, the onsite 345-kV station switchyard 

9 serves this purpose (Exelon 2013b). The switchyards are adjacent to Units 1 and 2 and within 

10 the boundary of the Byron site (see Figure 3–3). Therefore, the above discussion of the 

11 affected terrestrial environment for the Byron site is representative of the affected environment 

12 for the inscope transmission lines.

13 3.6.4 WHC Wildlife at Work Program

14 The Wildlife Habitat Council (WHC) Wildlife at Work Program provides a structure for 

15 corporations to implement voluntary conservation efforts that exceed regulatory requirements 

16 (WHC 2014). These habitat projects can vary in size and scope and emphasize community 

17 involvement and collaboration.

18 Exelon (a WHC member since 2005) established a Wildlife at Work Program at Byron with the 

19 mission of increasing biodiversity at the Byron site. The program focuses on the management 

20 and monitoring of individual onsite habitat projects. The program at Byron is managed by the 

21 Byron Environmental Stewardship Team, which has up to 25 members (Starke and Cox 2011).

22 There are several ongoing projects that are part of Byron’s Wildlife at Work Program. First is 

23 the enhancement of habitats for cavity-nesting birds, which provides houses for local birds in 

24 need of nesting areas. According to Exelon’s monitoring of this project, the bird houses located 

25 in meadows and wooded areas on the Byron property have been successful in encouraging 

26 bluebirds (Sialia sialis) and wood ducks (Aix sponsa) to utilize the habitats present at Byron 

27 (Exelon 2011b). An increase in the number of bluebirds has been observed in the project area, 

28 along with an increase in the number of houses with chicks that have fledged. The number of 

29 wood duck houses with ducklings has also increased (Starke and Cox 2011).

30 The second project is the enhancement of habitats for bats, which provides houses for local bat 

31 species. This project began in 2007 after Byron personnel noticed bats roosting under an 

32 awning on one of the main facility buildings. The bat houses were constructed to encourage the 

33 bats to roost nearer to the Rock River where there is a more abundant food supply of insects for 
Affected Environment

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1 the bats. Although deposits found on the foliage below the bat houses suggest the presence of 

2 bats, relatively few observations of bats using the houses have been made. Also, no 

3 observations or surveys have been conducted using trained biologists to determine the species 

4 of bat present on the site (Exelon 2013b; Starke and Cox 2011).

5 The third ongoing project on site is a butterfly garden, which provides food and cover for a 

6 variety of different species. The garden was established outside the training building and has 

7 proven very successful in attracting different pollinators, birds, and butterflies. According to 

8 Exelon, employees and visitors to the Byron site have had a very positive reaction to this project 

9 in particular (Starke and Cox 2011).

10 As part of the Wildlife at Work program, Exelon plans to continue to maintain and monitor 

11 existing bird and bat houses, as well as the butterfly garden. Future potential projects being 

12 discussed include the installation of heron platforms along the Rock River, the creation of 

13 retention ponds on the property where birds and animals would have increased access to water, 

14 and the possible addition of prairie plant habitat on the Byron property (Starke and Cox 2011).

15 3.7 Aquatic Resources

16 Rock River

17 The Byron site is located 2 mi (3.2 km) east of the Rock River from which the facility withdrawals 

18 and discharges cooling system make-up and blowdown water. From its source in the Horicon 

19 Marsh in Dodge County, Wisconsin, the Rock River meanders south to the Wisconsin–Illinois 

20 state line and then southwest through Illinois to its confluence with the Mississippi River at Rock 

21 Island, Illinois. The river flows a total length of 318 mi (512 km). The river’s watershed covers 

an area of approximately 28,270 km2 (10,915 mi2 22 , 6,985,600 ac, or 2,826,972 ha), of which 

14,633 km2 (5,650 mi2 23 , 3,616,000 ac, or 1,463,343 ha) are in Illinois. The primary land use 

24 within the Rock River basin is agricultural. The largest tributaries are the Pecatonica, the 

25 Kishwaukee, and the Green Rivers (Sinclair 1996).

26 The IDNR has designated the lower Rock River basin, which includes Ogle County and 

27 eight other Illinois counties, as a Resource Rich Area (Suloway et al. 1996). However, the lower 

28 basin is highly disturbed: in 2006, the IEPA reported that only about 412 ac (167 ha) of 

29 undegraded, high-quality natural habitat remained in this basin (IEPA 2006). Industrial point 

30 source discharge, agricultural runoff, and urbanization are the major sources of Rock River 

31 water quality degradation. Channelization beginning in the early 1900s, the installation of 

32 seven in-channel dams, and the drainage of wetlands have also reduced the quantity and 

33 quality of aquatic habitat in the basin (Sinclair 1996). The closest dam to Byron lies in Oregon, 

34 Illinois, approximately 8.0 km (5.0 mi) downstream of the Byron discharge (Exelon 2013a).

35 Aquatic Surveys and Monitoring

36 Prior to Byron construction and operation, ComEd commissioned Environmental Analysts, 

37 Inc. (EAI) to perform baseline monitoring of phytoplankton, zooplankton, benthic 

38 macroinvertebrate, and fish communities in the Rock River between 1972 and 1985 for the 

39 following sample periods: 1972 to 1974, 1975 to 1979, and 1983 to 1985. ComEd presented 

40 the baseline monitoring results from the 1972-to-1973 sampling year in its ER for Byron 

41 construction and the results from the 1973-to-1974 sampling year in its ER for Byron operation 

42 (ER-O) (ComEd 1981). The NRC also provided brief summaries of the results of these studies 

43 in its Final Environmental Statements for Byron construction (FES-C) (AEC 1974) and operation 

44 (FES-O) (NRC 1982).
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1 Following the commencement of Byron operation (Unit 1 in September 1985; Unit 2 in 

2 August 1987), aquatic surveys of fish and benthos continued from 1986 through 2002 and 

3 in 2011. Exelon commissioned EA Engineering, Science, and Technology (EA Engineering, 

4 successor to EAI) to perform the 2011 survey (EA Engineering 2012) in support of the 

5 preparation of Exelon’s license renewal application. All of the preoperational and operational 

6 studies collected samples at the same locations: five transects in the Rock River (from a point 

7 2.4 mi (3.9 km) upstream of Byron, Illinois, to just upstream of the dam at Oregon, Illinois) and 

8 at the mouths of six tributary streams that flow into the Rock River near the Byron site (Stillman 

9 Creek, Mill Creek, Woodland Creek, Leaf River, Spring Creek, and Silver Creek). Table 3–10 

10 lists and describes these locations, and Figure 3–12 illustrates the sampling locations.

11 In 1986 and 1987, biologists from the Illinois Natural History Survey (INHS) surveyed fish in the 

12 Rock River near Castle Rock State Park as well as in three nearby tributary streams to support 

13 an IDOT road improvement project (Wetzel et al. 1998). Although this study was unrelated to 

14 Byron, the study site was located approximately 10 mi (16 km) downstream of the Byron 

15 discharge. 

16 Table 3–10. Sampling Locations for Preoperational and Operational Aquatic Monitoring 

17 and Surveys of the Rock River

Location Description

Rock River Transects

R-1 2.4 mi (3.9 km) upstream of Byron, IL; represents conditions well above (upriver of) the 

Byron intake

R-2 300 yd (270 m) upstream of the blowdown discharge point; represents conditions in the 

vicinity of the Byron intake

R-3 at the Byron blowdown discharge point

R-4 0.7 mi (1.1 km) downstream of the blowdown discharge point; represents conditions 

inclusive of Byron’s thermal plume

R-5 3.4 mi (5.5 km) downstream of Byron and 1,000 yd (910 m) above the dam at Oregon, IL; 

represents conditions well below (downriver of) Byron

Tributaries

S-1 Stillman Creek

S-2 Mill Creek

S-3 Woodland Creek (this creek was sampled at three pool locations: W-1, W-2, and W-3)

S-4 Leaf River

S-5 Spring Creek

S-6 Silver Creek

Source: ComEd 1981

18 In 1993, ComEd commissioned Ecological Specialists, Inc. (ESI), to conduct a mussel study 

19 within the Rock River near the Byron intake and discharge points. Exelon commissioned ESI to 

20 repeat this survey in 2011 (ESI 2011) in support of the preparation of Exelon’s license renewal 

21 application.
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1 Figure 3–12. Rock River Aquatic Survey Sampling Locations

2 

3 Source: ComEd 1981, Figure 2.2-1 

ROCK 

CREEK 

LEGEND: 

I · RIVER TRANSECT 

S · STRlU SUTIOII 

W • POOL STUIOII 

0 • SEIIIIIIC LOCATION 

0 · IYRDII STUIOII 

1·1 
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1 The following sections characterize the aquatic communities in the vicinity of Byron by 

2 summarizing the results of the available studies.

3 Phytoplankton

4 EAI conducted the first phytoplankton survey near the Byron site on 15 sample days between 

5 May 1972 and June 1973 at five river transection locations (R-1 through R-5) and at 

6 three tributary mouths (S-3, S-4, and S-5) by immersing several 1-L (liter) polypropylene bottles 

7 beneath the surface of the water. The FES-C (AEC 1974) provides a brief summary of the first 

8 sample year. The FES-C states that between 7 and 37 phytoplankton species were identified 

9 on each sample day, and the biovolume of each sample ranged from less than 1 microliter per 

10 liter (μL/L) in winter to over 40 μL/L in late summer. A group of about eight centric diatom 

11 species dominated the samples by biomass and were those typical of the upper Mississippi 

12 River Basin (which includes the Rock River Basin), including: Melosira ambigua, 

13 Stephanodiocus hantzchii, S. niagarae, S. astraea minutula, and Cyclotella meneghiniana. 

14 Green, blue--green, and euglenoid algae were of localized abundance on certain sample days 

15 and were very rare during the colder months. Filamentous blue-green algae were most 

16 abundant in September and August. The FES-C concluded that the Rock River in the vicinity of 

17 the Byron site is a moderately eutrophic stream with planktonic flora normal for the region.

18 In the second sample year (September 1973 through October 1974), EAI surveyed 

19 phytoplankton at four of the five river transection locations (R-2 through R-5) and at the mouths 

20 of two tributaries (S-4 and S-5) on 6 sample days. ComEd (1981) reported the results of this 

21 sample year in its ER-O. The survey yielded a total of 119 taxa, which included 59 diatoms 

22 (comprising 93.7 percent of all collected phytoplankton), 43 green algae (3.3 percent), 

23 9 blue-green algae (2.4 percent), 4 euglenids (0.1 percent), 2 dinoflagellates (less 

24 than 0.1 percent), 1 golden algae (0.5 percent), and 1 cryptomonad (less than 0.1 percent). The 

25 same diatom species dominated the samples by biomass as those in the first sample year with 

26 the additional mention of M. granulata, M. granulata var. angustissima, S. minutus, S. subtilus, 

27 and Nitzschia palea as frequently collected species.

28 Zooplankton

29 EAI conducted a zooplankton survey on 19 sample days between April 1972 and June 1973 at 

30 five river transection locations (R-1 through R--5) and at three tributary mouths (S-3, S-4, and 

31 S-5) by pouring 60 L (20 gal) of surface water through a #20 mesh plankton net. The FES-C 

32 (AEC 1974) provides a brief summary of the first sample year. The FES-C states that EAI 

33 collected 38 rotifer species and 31 protozoan species. Of these, 7 rotifers and 5 protozoa 

34 occurred on more than two-thirds of sample days. Rotifers in the genera Keratella, Polyarthra, 

35 and Brachionus and protozoa in the genera Centropyxis, Difflugia, and Vorticella were most 

36 common. One species of copepod (Cyclops bicuspidatus) was also frequently collected. 

37 Zooplankton were most abundant in spring and fall samples and least abundant in summer and 

38 winter samples.

39 In the second sample year (September 1973 through October 1974), EAI surveyed the same 

40 sampling locations as in the previous sample year, but on fewer occasions (6 sample days). 

41 ComEd (1981) reported the results of the second sample year in its ER-O. The survey collected 

42 18 rotifer species, 14 protozoan species, 7 cladoceran species, 3 copepod species, 2 tardigrade 

43 species, as well as unspecified nematodes, oligochaetes, and chironomids. As in the first 

44 sample year, rotifers were the numerically dominant taxa at both Rock River and tributary 

45 sampling locations. The most commonly occurring forms included the juvenile copepod stages 

46 (nauplii and copepodites), the cladocerans Bosmina and Chydorus, and the rotifer genera 

47 Brachionus, Keratella, and Synchaeta. Zooplankton samples exhibited summer and winter lows 

48 and spring and fall peaks ranging from 2 organisms per L (R-2, January 1974) to 350 organisms 
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1 per L (R-2, April 1974), which corresponded to abundance measurements during the first 

2 sample year.

3 Periphyton Artificial Substrate Samplers

4 Information on the first year of periphyton sampling was not included in the FES-C (AEC 1974); 

5 therefore, only the sampling results from the second sample year are discussed below. 

6 ComEd’s ER-O (1981) notes that periphyton data collected during the second sample year did 

7 not deviate markedly from the information collected during the corresponding seasons of the 

8 first sample year.

9 EAI sampled periphyton with artificial substrate samplers at the five river stations (R-1 through 

10 R-5), four tributary stream stations (S-3, S-4, and S-5 from September through December 1973, 

11 and S-3, S-5, and S-6 from January through September 1974), and two Woodland Creek pool 

12 stations (W-1 and W-2) from September 1973 through September 1974. A total of 266 algae 

13 taxa were identified from all samples, which included 181 diatoms, 64 green algae, 1 golden 

14 algae, 12 blue-green algae, 7 euglenids, and 1 dinoflagellate. Diatoms dominated the samples, 

15 and the most commonly collected forms included Melosira ambigua, M. granulata

16 var. angustissima, Nitzschia linearis, Navicula viridula var. avenacea, Gomphonema olivaceum, 

17 and G. parvulum, all of which are commonly found in eutrophic waters.

18 Zoobenthos

19 The FES-C (AEC 1974) indicates that EAI sampled zoobenthos on 7 days between May 1972 

20 and June 1973. Samples were dominated by four groups of invertebrates: oligochaete worms 

(family Tubuficidae, 9 taxa, 147.3 organisms per square meter (m2 21 )), mayfly larvae (order 

Ephemeroptera, 5 taxa, 9.6/m2

), caddisfly larvae (order Trichoptera, 2 taxa, 15.7/m2 22 ), and midge 

fly larvae (family Chironomidae, 21 taxa; 20.1/m2 23 ). Caddis fly and mayfly larvae numbers were 

24 lower in fall, which correlates with the time during which mature larvae would emerge from the 

25 stream.

26 ComEd’s ER-O (1981) provides more detailed information on zoobenthos collected during the 

27 second sample year (1973 to 1974). EAI collected PONAR dredge samples on 6 sample days 

28 between September 1973 and October 1974 at river sampling locations R-1 through R-5 and 

29 tributary locations S-3, S-5, W-1, and W-3. These locations included a variety of substrate 

30 types. Samples containing coarse gravel supported the greatest number of invertebrate taxa 

31 (93), followed by samples containing sand (77 taxa), fine gravel (43 taxa), silt (40 taxa), muck 

32 (40 taxa), fine rubble (17 axa), detritus (11 taxa), and mollusk shells (3 taxa). The same 

33 four groups of invertebrates dominated the second year samples as those that dominated the 

34 first year. However, midge fly larvae were the most prevalent taxa in the second year. Samples 

35 also included two species of family Naididae (aquatic worms), two species of leeches (class 

36 Hirudinea), five genera of dragonflies (order Odonata), nine genera of beetles (order 

37 Coleoptera), true flies (order Diptera), flatworms (class Turbellaria), roundworms (phylum 

38 Nematoda), and water mites (subclass Acari).

39 Ichthyoplankton

40 The FES-C (AEC 1974) and FES-O (NRC 1982) indicate that ichthyoplankton (fish eggs and 

41 larvae) densities were very low at Rock River sampling locations during preoperational surveys 

(one egg or larvae per 100 cubic meters (m3

) (3,500 cubic feet (ft3 42 ))) in 1972 to 1973 and 

six larvae per 100 m3 (3,500 ft3 43 ) in 1973 to 1974). Ichthyoplankton densities were higher at 

44 tributary sampling locations, which the FES-O attributed to washout from spawning sites. In 

1973, three sampled streams averaged a density of 288 eggs or larvae per 100 m3 (3,500 ft3 45 ). 

46 Larvae of minnows (family Cyprinidae), suckers (family Catastomidae), bullhead catfishes 

47 (family Ictaluridae), and sunfishes (family Centrarchidae) were the most commonly collected.
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1 Mussels

2 In 2009, Bales et al. (2012) surveyed mussels at 36 sites in the Rock River and its tributaries by 

3 hand grabbing and visual detection when water conditions permitted. The survey found 

4 27 extant species across the river basin. The pimpleback (Quadrula pustulosa) occurred at all 

5 mainstem sample sites, and the plain pocketbook (Lampsilis cardium), fragile papershell 

6 (Leptodea fragilis), State-threatened black sandshell (Ligumia recta), Wabash pigtoe (Fusconaia 

7 flava), and pink papershell (Potamilus ohiensis) were also commonly occurring species at the 

8 majority (50 to 86 percent) of sites. One of the sample sites was 1 mi (1.6 km) downstream of 

9 Byron (Site No. 4). This site yielded eight species with live individuals (L) or fresh dead shells 

10 (FD): paper pondshell (Utterbackia imbecillis, 1 L), Wabash pigtoe (3 L), pimpleback (23 L), 

11 plain pocketbook (15 L), fragile papershell (unspecified number of FD), black sandshell (1 L), 

12 pink papershell (1 L), and lilliput (Toxolasma parvum, 1 L).

13 The first mussel survey in the direct vicinity of the Byron site was conducted in 1993 by ESI to 

14 determine if mussels would be affected by the construction of sediment control structures. 

15 During that study, ESI collected 21 species of mussels, 7 of which were only collected as 

16 weathered shells.

17 In 2011, ESI (2011) repeated the 1993 survey along 25 100-m (330-ft) transects that ran 

18 perpendicular to the bank starting 800 m (0.5 mi) upstream of the Byron discharge and 

19 continuing at 100-m (330-ft) intervals to a point 1,600 m (1 mi) downstream of the discharge. 

20 For each sample, a diver searched each transect line for a minimum of 3 minutes and collected 

21 all mussels encountered within 1 m (3.2 ft) of the line. Several quantitative and qualitative 

22 samples were also collected within areas of mussel concentrations to estimate density and 

23 species richness.

24 A total of 21 species were collected during the study, only 8 of which were collected as live 

25 individuals. Pimpleback (93.1 percent of individuals collected) overwhelmingly dominated the 

26 live samples, followed by plain pocketbook (4.1 percent) and Wabash pigtoe (1.0 percent). The 

27 remaining live species were fatmucket clam (Lampsilis siliquoidea, 0.5 percent), fragile 

28 papershell (0.5 percent), round pigtoe (Pleurobema sintoxia, 0.3 percent), white heelsplitter 

29 (Lasmigona complanata complanata, 0.3 percent), and pink papershell (0.2 percent). No 

30 Illinois-protected species were collected alive, although ESI collected weathered shells of 

31 four species: purple wartyback (Cyclonaias tuberculata, State-threatened), spike (Elliptio 

32 dilatata, State-threatened), sheepnose (Plethobasus cyphyus, State-endangered), and black 

33 sandshell (State-threatened). The butterfly mussel (Ellipsaria lineolata, State-threatened) was 

34 collected as a subfossil shell.

Mussel density was relatively high (12.0 individuals per 1 m2 35 (11 square feet)). Mussels were 

36 most abundant within the transition zone between cobble/gravel/sand substrate and sand 

37 substrate. The average number of mussels was also significantly higher along the east bank 

38 (1.5 individuals per 10 by 1 m (32 by 3.2 ft) section) than along the west bank 

39 (0.6 individuals/section). Mussels were also more abundant upstream (1.8 individuals/section) 

40 of Byron than downstream (0.5 individuals/section). ESI determined that this was not 

41 temperature related, because the thermal plume was limited to an area near the west bank and 

42 mussel densities abundance in semiquantitative samples did not differ significantly between 

43 upstream and downstream locations along that bank. Samples were composed of both young 

44 and old individuals, and half of the individuals collected were over 5 years old. Only 3.2 percent 

45 of mussels collected were fresh dead shells, which indicates that the community has a low 

46 mortality rate.

47 As a result of the 2011 study, ESI concluded that while species richness declined between the 

48 1993 and 2011 study, a level-of-effort comparison between the two studies indicated that 
Affected Environment

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1 species abundance increased. Both studies yielded the most individuals in a thin strip of 

2 transitional substrate along the east bank, and more individuals occurred upstream than 

3 downstream.

4 Fish

5 Beginning in 1972, EAI surveyed the Rock River fish community near Byron at the five river 

6 sampling locations (R-1 through R-5) and at the mouths of the tributary streams listed in 

7 Table 3–10. The results of the first sample year (1972 to 1973) were not reported in the FES-C 

8 (AEC 1974), but some of the results of the first year are summarized in ComEd’s ER-O (1981). 

9 Its ER-O also describes the results of the second sample year (1973 to 1974).

10 EAI conducted fish samples with seines and by electrofishing. Seine samples were collected 

11 with 10-ft and 50-ft beach seines with 1/4-in. mesh. Electrofishing was conducted with a 

12 230-volt, 2,000-watt, 3-phase AC generator for 15 minutes on each side of the river at each of 

13 the river stations. Beginning in 1974, hoop nets were also used to sample fish. EAI collected 

14 42 species representing 8 families in the first sample year (1972 to 1973) and 31 species in 

15 8 families in the second sample year (1973 to 1974). The 1972-to-1973 surveys included a 

16 greater variety of minnows (Pimephales spp.), catfishes, and sunfishes (Lepomis spp.), while 

17 the 1973-to-1974 surveys collected greater numbers of carpsuckers (Carpiodes spp., 

18 40.2 percent of individuals collected) and channel catfish (Ictalurus punctatus, 19.1 percent). 

19 ComEd (1981) attributed this shift in collected species on changes in gear type (hoop nets 

20 beginning in 1974) and effort (decrease in seining effort in several shallow areas in the second 

21 sample year). Channel catfish dominated the game species collected in 1973 to 1974; 

22 14 species of game fish were collected, which accounted for over 30 percent of total fish 

23 collected, and 62 percent of these were channel catfish. The baselines studies found no 

24 significant difference in the abundance or diversity of fish caught at the different sampling 

25 locations. Table 3–11 lists the species collected during the 1973-to-1974 sample year and 

26 relative abundance of each.

27 Preoperational monitoring continued until Byron began operating in 1985. The FES-O 

28 (NRC 1982) provides limited information about the results of monitoring between 1975 and 

29 1982, when the FES-O was published. Between 1975 and 1979, an additional eight species of 

30 fish were collected that had not appeared in the first or second sample years. Channel catfish 

31 continued to be the most abundant game fish collected in 1975 to 1976 and 1976 to 1977; 

32 bluegill (Lepomis macrochirus) was the most abundant game species collected from 1977 to 

33 1978; and black crappie (Pomoxis nigromaculatus) was most abundant in 1978-to-1979 and 

34 1979-to-1980 collections.

35 In 1986 and 1987, biologists from INHS conducted fish surveys in Rock River adjacent to Castle 

36 Rock State Park, which lies approximately 10 mi (16 km) downstream of the Byron discharge, 

37 as well as in three tributary streams, to support an IDOT road improvement project (Wetzel 

38 et al. 1988). Within the Rock River, INHS biologists collected minnow seine and bag seine 

39 samples on September 4, 1986, in two narrow reaches of the river in waters of 0 to 5 ft (0 to 

40 1.5 m). The minnow seines were 4 by 10 ft (1.2 by 3.0 m) in size with 1/4-in. mesh. Biologists 

41 took at least 10 hauls per site and continued sampling at each site until no additional species 

42 were collected. Bag seines were 4 by 30 ft (1.2 by 9.1 m) in size with 1/4-in. mesh. Biologists 

43 also continued bag seine sampling until no additional species were collected.
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1 Table 3–11. Fish Species Collected in the Vicinity of Byron During EAI Baseline 

2 Monitoring, 1973–1974

Species Common Name

No. Individuals Collected (a)

Relative 

Abundance (% 

Collected)

Rock 

River Tributaries Total

Catostomidae Suckers 313 232 545 49.5

Carpiodes carpio river carpsucker 157 118 275 25.0

Carpiodes cyprinus quillback carpsucker 76 92 168 15.2

Moxostoma 

macrolepidotum northern redhorse 53 9 62 5.6

Catostomas commersoni white sucker 22 11 33 3.0

Ictiobus cyprinellus bigmouth buffalo 3 0 3 0.3

Moxostoma spp. redhorse spp. 2 0 2 0.2

Hypentelium nigricans hog sucker 0 1 1 0.1

Ictiobus bubalus smallmouth buffalo 0 1 1 0.1

Cyprinidae Minnows 161 52 213 19.3

Cyprinus carpio carp 104 39 143 13.0

Notropis atherinoides emerald shiner 40 6 46 4.2

Pimephales vigilax bullhead minnow 8 3 11 1.0

Pimephales notatus bluntnose minnow 5 1 6 0.5

Semotilus atromaculatus creek chub 2 0 2 0.2

Notropis stramineus sand shiner 0 2 2 0.2

Carassius auratus goldfish 1 0 1 0.1

Hybopsis storeriana silver chub 1 0 1 0.1

Notropis spilopterus spottail shiner 0 1 1 0.1

Ictaluridae Bullhead Catfishes 207 4 211 19.2

Ictalurus punctatus channel catfish 206 4 210 19.1

Ictalurus melas black bullhead 1 0 1 0.1

Centrarchidae Sunfishes 84 29 113 10.3

Pomoxis nigromaculatus black crappie 38 9 47 4.3

Pomoxis annularis white crappie 28 7 35 3.2

Lepomis macrochirus bluegill 8 8 16 1.5

Micropterus salmoides largemouth bass 5 3 8 0.7

Micropterus dolomieu smallmouth bass 2 1 3 0.3

Lepomis humilis orangespotted 

sunfish 2 1 3 0.3
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Species Common Name

No. Individuals Collected (a)

Relative 

Abundance (% 

Collected)

Rock 

River Tributaries Total

Lepomis cyanellus green sunfish 1 0 1 0.1

Moronidae Temperate Basses 8 0 8 0.7

Morone chrysops white bass 6 0 6 0.5

Morone mississippiensis yellow bass 2 0 2 0.2

Percidae Perches 3 3 6 0.6

Etheostoma nigrum johnny darter 2 2 4 0.4

Stizostedion vitreum walleye 1 1 2 0.2

Esocidae Pikes 1 4 5 0.5

Esox Lucius northern pike 1 4 5 0.5

Sciaenidae Drums 1 0 1 0.1

Aplodinotus grunniens freshwater drum 1 0 1 0.1

TOTAL 778 324 1,102 100.0

(a) Samples collected from Rock River sample locations R-1, R-2, R-3, R-4, and R-5; Woodland Creek (S-3); Leaf 

River (S-4); Spring Creek (S-5); and Silver Creek (S-6). Species arranged by number collected.

Source: ComEd 1981

1 In total, INHS collected 37 species of fish representing 8 families and 24 genera, of which 

2 25 species representing 7 families and 16 genera were collected from two sampling transects in 

3 the Rock River. Cyprinids were most commonly collected. Spotfin shiner (Cyprinella 

4 spilopterus), which accounted for 63.1 percent of fish collected in the river, was the most 

5 prevalent cyprinid, followed by bullhead minnow (Pimephales vigilax, 7.1 percent), bluntnose 

6 minnow (Pimephales notatus, 6.9 percent), and striped shiner (Luxilus chrysocephalus, 

7 5.8 percent). Game fishes were less commonly collected than would be expected: black 

8 crappie, largemouth bass (Micropterus salmoides), and bluegill accounted for 3.9, 1.2, and 

9 1.1 percent of Rock River collections, respectively. The low collection frequency of these 

10 species was likely due to sampling gear. Seines are only effective in shallow areas with 

11 relatively flat bottoms. Electrofishing or a mix of sampling gear designed for a wider variety of 

12 microhabitats may have returned a more diverse and representative collection of fish. Thus, 

13 while the INHS study indicates certain species’ presence, it does not necessarily accurately 

14 account for those species’ abundance. One State-listed threatened species was collected 

15 during this survey: a single gravel chub (Erimystax x-punctatus). Table 3–12 lists all species 

16 collected in the Rock River during the INHS study.
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1 Table 3–12. Fish Species Collected Downstream of Byron During INHS Study, 1986–1987

Individuals Collected at 

Rock River Sampling 

Locations (a)

Species Common Name Number Percent (%)

Cyprinella spiloptera spotfin shiner 358 63.1

Pimephales vigilax bullhead minnow 40 7.1

Pimephales notatus bluntnose minnow 39 6.9

Luxilus chrysocephalus striped shiner 33 5.8

Pomoxis nigromaculatus black crappie 22 3.9

Notropis stramineus sand shiner 17 3.0

Notropis hudsonius spottail shiner 11 1.9

Micropterus salmoides largemouth bass 7 1.2

Lepomis macrochirus bluegill 6 1.1

Etheostoma zonale banded darter 6 1.1

Notropis flavus stonecat 4 0.7

Lepomis humilis orangespotted sunfish 4 0.7

Stizostedion vitreum walleye 4 0.7

Esox Lucius northern pike 3 0.5

Percina phoxocephala slenderhead darter 2 0.4

Etheostoma nigrum johnny darter 2 0.4

Nocomis biguttatus hornyhead chub 1 0.2

Erimystax x-punctata gravel chub 1 0.2

Pimephales promelas fathead minnow 1 0.2

Carpiodes cyprinus quillback 1 0.2

Moxostoma erythrurum golden redhorse 1 0.2

Moxostoma macrolepidotum northern redhorse 1 0.2

Pylodictis olivaris flathead catfish 1 0.2

Labidesthes sicculus brook silverside 1 0.2

Lepomis cyanellus green sunfish 1 0.2

TOTAL 567 100

(a) Species arranged by number collected.

Source: Wetzel et al. 1988

2 In August 2011, EA Engineering (2012) conducted electrofishing and seine samples at River 

3 locations R-2, R-3, R-4, and R-5 and at the mouth of Spring Creek (S-5). Each transect was 

4 sampled on the east bank (L) and west bank (R) and results were reported in terms of both 

5 sampling transect and bank (i.e., R-1L, R-1R, R-2L, R-2R, etc.). Fish were collected by both 
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1 electrofishing and seining on August 29 and 30. Electrofishing was conducted using a 

2 boat-mounted boom-type electrofishing system for 30-minute durations in a downstream 

3 direction. Seining was conducted with seines 25 by 6 ft (7.6 by 1.8 m) in size with 3/16-in. ace 

4 mesh along 15-m (49.2-ft) transects of shoreline in a downstream direction. Seining and 

5 electrofishing were conducted on different days to avoid bias.

6 EA Engineering collected a total of 2,577 fish (1,794 individuals with seines and 783 individuals 

7 with electrofishing gear) of 28 species representing 10 families during the study. While seining 

8 collected the most individuals, electrofishing collected a more diverse sample that appears to 

9 better represent the fish community near Byron. As in the previous studies near Byron, 

10 cyprinids accounted for the overwhelming majority of individuals collected, with spotfin shiner 

11 and bullhead minnow being particularly abundant (accounting for 40.2 and 25.0 percent of the 

12 total individuals collected, respectively) and sand shiner (Notropis stramineus) and bluntnose 

13 minnow being relatively common at 8.3 and 4.2 percent, respectively. Collected sport fish 

14 included smallmouth bass (Micropterus dolomieu, 4.0 percent), channel catfish (1.4 percent), 

15 and largemouth bass (0.8 percent). Gizzard shad (Dorosoma cepedianum, 4.9 percent) and 

16 freshwater drum (Aplodinotus grunniens, 3.8 percent) were also relatively common. The 

17 remaining 18 species each accounted for less than 2 percent of collected individuals (see 

18 Table 3–13). No State-listed endangered or threatened fish were collected during this study.

19 During electrofishing samples, sampling location R-3R (along the west bank of the Rock River 

20 upstream of Byron’s discharge) yielded the highest number of fish (234 individuals), while the 

21 lowest numbers were collected at the mouth of Spring Creek (S-5, 64 individuals) and along the

22 east river bank upstream of the discharge point (R-2L, 67 individuals). Similar numbers were 

23 collected at the remaining sample locations (87 to 89 fish). Species composition ranged from 

24 12 taxa (R-2R) to 17 taxa (R-3R, R-4L). Seven species—gizzard shad, spotfin shiner, bullhead 

25 minnow, channel catfish, green sunfish (Lepomis cyanellus), smallmouth bass, and freshwater 

26 drum—were collected at each of the seven sampling locations. The mean catch per effort 

27 (CPE) for fish collected at all sampling locations was 224.0 fish/hour (fish/hr). Mean CPE for 

28 sampling locations upstream of the Byron discharge (R-2L, R-2R) was 154 fish/hr, while mean 

29 CPE at downstream locations (R-3L, R-3R, R-4L, R-4R, S-5) was 251.6 fish/hr. The CPE was 

30 higher along the east river bank (“L” sample locations), on which Byron is located, which was 

31 mainly due to higher catches of spotfin shiner and bullhead minnow at these locations.

32 During the seine samples, the most fish (965 individuals) were collected along the east river 

33 bank near the discharge (R-3L), and the fewest number of fish (24) were collected along the 

34 west river bank near the discharge (R-3R). Species composition ranged from 6 taxa along the 

35 east bank upstream of the discharge (R-2L) and along the east bank downstream of the 

36 discharge (R-4L) to 10 taxa along the west bank upstream of the discharge (R-2R) and along 

37 the east bank near the discharge (R-3L). Four species—spotfin shiner, bluntnose minnow, 

38 bullhead minnow, and smallmouth bass—were collected at each of the seven sampling 

39 locations, and one species—sand shiner—was collected at six locations.
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1 Table 3–13. Fish Species Collected in the Vicinity of Byron During EA Engineering 

2 Survey, 2011

Species Common Name

Individuals Collected(a)

Electrofishing Seine Combined Percent 

(%)

Cyprinella spiloptera spotfin shiner 148 889 1,037 40.2

Pimephales vigilax bullhead minnow 103 540 643 25.0

Notropis stramineus sand shiner 24 189 213 8.3

Dorosoma cepedianum gizzard shad 108 17 125 4.9

Pimephales notatus bluntnose minnow 28 81 109 4.2

Micropterus dolomieu smallmouth bass 82 20 102 4.0

Aplodinotus grunniens freshwater drum 99 0 99 3.8

Lepomis huxnilis bluegill 33 14 47 1.8

Notropis atherinoides emerald shiner 20 17 37 1.4

Ictalurus punctatus channel catfish 28 9 37 1.4

Lepornis cyanellus green sunfish 28 0 28 1.1

Micropterus salrnoides largemouth bass 18 3 21 0.8

Carpiodes cyprinus quillback 12 0 12 0.5

Moxostorna anisuruin silver redhorse 12 0 12 0.5

Cyprinus carpio common carp 10 1 11 0.4

Carpiodes spp. and/or

Ictiobus spp. Ictiobinae spp. 0 7 7 0.3

Moxostoma macrolepidotum shorthead redhorse 6 0 6 0.2

Carpiodes carpio river carpsucker 5 0 5 0.2

Moxostoma erythrurum golden redhorse 4 0 4 0.2

Etheostoma nigrum johnny darter 1 2 3 0.1

Morone chrysops white bass 3 0 3 0.1

Notropis spp. Notropis spp. 1 1 2 0.1

Pylodictis olivaris flathead catfish 2 0 2 0.1

Labidesthes sicculus brook silverside 2 0 2 0.1

Lepornis spp. Lepomis spp. 0 2 2 0.1

Lepomis humilis orangespotted 

sunfish 0 2 2 0.1

Luxilus cornutus common shiner 1 0 1 <0.1

Sander vitreus walleye 1 0 1 <0.1

Esox Lucius northern pike 1 0 1 <0.1

Ictiobus cyprinellus bigmouth buffalo 1 0 1 <0.1
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Species Common Name

Individuals Collected(a)

Electrofishing Seine Combined Percent 

(%)

Moxostoma duquesnei black redhorse 1 0 1 <0.1

Lepomis hybrid Lepomis hybrid 1 0 1 <0.1

TOTAL 783 1,794 2,577 100

(a) Species arranged by number collected.

Source: EA Engineering 2012

1 3.8 Special Status Species and Habitats

2 This section addresses species and habitats that are Federally protected under the Endangered 

3 Species Act of 1973 (16 U.S.C. § 1531 et seq., herein referred to as ESA) and the 

4 Magnuson–Stevens Fishery Conservation and Management Reauthorization Act, as amended 

5 (16 U.S.C. §§ 1801–1884, herein referred to as MSA). The ESA, along with the MSA, put 

6 requirements on Federal agencies such as the NRC. The terrestrial and aquatic resource 

7 sections (Sections 3.6 and 3.7, respectively) discuss other species and habitats protected by 

8 other Federal acts and the State of Illinois that do not put requirements on the NRC.

9 3.8.1 Species and Habitats Protected Under the Endangered Species Act

10 The FWS and the National Marine Fisheries Service (NMFS) jointly administer the ESA. The 

11 FWS manages the protection of, and recovery effort for, listed terrestrial and freshwater 

12 species, and NMFS manages the protection of and recovery effort for listed marine and 

13 anadromous species. This section describes the action area and considers those species that 

14 could occur in the action area under both FWS’s and NMFS’s jurisdictions.

15 3.8.1.1 Action Area

16 The implementing regulations for section 7(a)(2) of the ESA define “action area” as all areas 

17 affected directly or indirectly by the Federal action and not merely the immediate area involved 

18 in the action (50 CFR 402.02). The action area effectively bounds the analysis of 

19 ESA-protected species and habitats because only species that occur within the action area may 

20 be affected by the Federal action.

21 For the purposes of the ESA analysis in this SEIS, the NRC staff considers the action area to be 

22 the Byron site (described in Sections 3.1 and 3.6) and the Rock River (described in Section 3.7) 

23 from 300 yd (270 m) upstream of the cooling tower blowdown discharge point and extending 

24 0.7 mi (1.1 km) downstream of the discharge point. This area of the river corresponds to the 

25 area that EAI and EA Engineering, Science, and Technology determined to be inclusive of 

26 effects from Byron operations during preoperational and operational aquatic monitoring (as 

27 discussed in Section 3.7). The NRC staff expects all direct and indirect effects of the proposed 

28 action to be contained within these areas.

29 The NRC staff recognizes that while the action area is stationary, Federally listed species can 

30 move in and out of the action area. For instance, a migratory fish species could occur in the 

31 action area seasonally as it travels up and down the river past Byron. Similarly, a flowering 

32 plant known to occur near, but outside, of the action area could appear within the action area 

33 over time if its seeds are carried into the action area by wind, water, or animals. Thus, in its 
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1 analysis, the NRC staff considers not only those species known to occur directly within the 

2 action area, but those species that may passively or actively move into the action area. The 

3 staff then considers whether the life history of each species makes the species likely to move 

4 into the action area where it could be affected by the proposed Byron license renewal.

5 Within the action area, Federally listed terrestrial species could experience impacts such as 

6 habitat disturbance associated with refurbishment or other ground-disturbing activities, cooling 

7 tower drift, collisions with cooling towers and transmission lines, exposure to radionuclides, and 

8 other direct and indirect impacts associated with station, cooling system, and inscope 

9 transmission line operation and maintenance (NRC 2013a). The proposed action has the 

10 potential to affect Federally listed aquatic species in several ways: impingement or entrainment

11 of individuals into the cooling system; alteration of the riverine environment through water level 

12 reductions, changes in dissolved oxygen, gas supersaturation, eutrophication, and thermal 

13 discharges from cooling system operation; habitat loss or alteration from dredging; and 

14 exposure to radionuclides (NRC 2013a).

15 3.8.1.2 Species and Habitats under the FWS’s Jurisdiction

16 Table 3–14 identifies the species under FWS’s jurisdiction that occur within Ogle County. Ogle 

17 County includes approximately 488,000 ac (198,000 ha) of varying land uses and habitat types. 

18 Thus, a Federally listed species that occurs within Ogle County does not necessarily occur 

19 within the action area. The NRC staff uses this geographical range as a starting point for its 

20 analysis because Federally listed species distribution and critical habitat information is readily 

21 available at the county level. Additionally, the action area is a small area of land near the center 

22 of and wholly contained within the geographical boundaries of the county. Following the table, 

23 descriptions of each species include a determination of whether each species occurs in the 

24 action area based on the species’ habitat requirements, life history, and available occurrence 

25 information.

26 The NRC compiled the list of species in Table 3–14 from the FWS’s Endangered Species 

27 Program online database (FWS 2013b); correspondence between the NRC and the FWS 

28 (FWS 2013a; NRC 2013b, 2013c); the Illinois Natural Heritage Database (IDNR 2013); 

29 information from Exelon’s ER (Exelon 2013a); and available scientific studies, surveys, and 

30 literature. The NRC staff did not identify any candidate species or proposed or designated 

31 critical habitats within the action area.
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1 Table 3–14. Federally Listed Species in Ogle County, Illinois

Species Common Name Federal 

Status (a) Habitat

Mammals

Myotis septentrionalis northern long-eared bat P 

Intact forest with relatively full 

canopy and oaks, maples, beech, 

or pine present

Myotis sodalis Indiana bat E 

Hardwood forests and hardwood–

pine forests; old-growth forest; 

agricultural lands and old fields

Plants

Lespedeza leptostachya prairie bush clover T Dry tallgrass prairie with gravelly 

soils

Platanthera leucophaea Eastern prairie fringed 

orchid T 

Mesic prairie, wetlands, sedge 

meadows, marsh edges, and 

bogs with full sun and little to no 

woody encroachments

Dalea foliosa leafy prairie clover E 

Mesic and wet-mesic dolomite 

prairie, limestone cedar glades, 

and limestone barrens

(a) E = endangered; T = threatened; P = proposed for Federal listing

Sources: Exelon 2013a; FWS 2013a, 2013b

2 Northern Long-Eared Bat (Myotis septentrionalis)

3 The FWS published a proposed rule to list the northern long-eared bat as endangered 

4 throughout its range on December 2, 2013 (78 FR 72058). The FWS did not propose to 

5 designate critical habitat for the species because it found that such habitat is “not determinable 

6 at this time” (78 FR 61046). White-nose syndrome, wind energy development, and loss of 

7 habitat specifically linked to surface coal mining in prime summer habitat are factors that have 

8 contributed to this species’ decline.

9 The northern long-eared bat is a medium-sized bat that is distinguished from other Myotis

10 species by its long ears, which average 0.7 in. (17 mm) in length. This bat inhabits 39 states in 

11 the eastern and north central United States and all Canadian provinces west to the southern 

12 Yukon Territory and eastern British Columbia. Populations tend to be patchily distributed across 

13 its range and are typically composed of small numbers. More than 780 winter hibernacula have 

14 been recorded in the United States (36 in Illinois), most of which contain only a few (one to 

15 three) individuals. The FWS recognize four United States populations. Northern long-eared 

16 bats inhabiting Illinois are considered part of the Midwest population (78 FR 61046).

17 In the Midwest, the northern long-eared bat is fairly common during summer mist-net surveys 

18 and is found infrequently in winter hibernacula surveys (78 FR 61046). The species is regularly 

19 caught in consistent numbers in mist-net surveys in the Shawnee National Forest 

20 (78 FR 61046), which lies about 320 mi (515 km) south of the Byron site. In summer, bats roost 

21 alone or in small colonies under the bark of live or dead trees; in caves or mines; or in 

22 manmade structures, such as barns, sheds, and other buildings. The species opportunistically 
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1 roosts in a variety of trees, including several species of oak, maple, beech, and pine 

2 (78 FR 61046). Carter and Feldhamer (2005) found that roosting females in southern Illinois 

3 prefer intact forest with greater canopy cover. Northern long-eared bats forage both in flight and 

4 on the ground and eat a variety of moths, flies, leafhoppers, caddisflies, and beetles. The 

5 species breeds from late July to early October, after which time it will migrate to winter 

6 hibernacula. Northern long-eared bats are short-distance migrators and will travel 35 to 55 mi 

7 (56 to 89 km) from summer roosts to winter hibernacula (78 FR 61046). Hibernating females 

8 store sperm until spring, and give birth to one pup approximately 60 days after fertilization 

9 (78 FR 61046). Females raise young in maternity colonies of up to 30 individuals 

10 (78 FR 61046).

11 The majority of the action area is developed or composed of unsuitable habitat types for 

12 hibernation, roosting, and foraging. The action area includes some small areas of mixed 

13 woodlands, which would likely not be adequately sized to support the northern long-eared bat’s 

14 preference for intact forests with relatively full canopy cover. The NRC staff did not identify any 

15 records or other studies that suggest the occurrence of northern long-eared bats in the action 

16 area, and in its ER, Exelon (Exelon 2013a) does not indicate awareness of any records or 

17 observations of the northern long-eared bat’s occurring on plant property.

18 Given the available information, the NRC staff concludes that the northern long-eared bat is 

19 unlikely to occur within the action area.

20 Indiana Bat (Myotis sodalis)

21 The FWS listed the Indiana bat as endangered in 1967 (32 FR 4001). The FWS designated 

22 critical habitat for the Indiana bat in 1976 (41 FR 41914) to include 11 caves and 2 mines in 

23 six states, including a cave in LaSalle County, Illinois. However, no critical habitat for this 

24 species occurs in Ogle County.

25 The Indiana bat is an insectivorous, migratory bat that inhabits the central portion of the Eastern 

26 United States and hibernates colonially in caves and mines. The decline of Indiana bats is 

27 attributed to urban expansion, habitat loss and degradation, human-caused disturbance of 

28 caves or mines, insecticide poisoning, and white-nose syndrome (FWS 2011; Pruitt and 

29 TeWinkel 2007).

30 During summer months, reproductive female bats tend to roost in colonies under slabs of 

31 peeling tree bark or cracks within trees in forest fragments, often near agricultural areas (Pruitt 

32 and TeWinkel 2007). Colonies may also inhabit closed-canopy, bottomland deciduous forest; 

33 riparian habitats; wooded wetlands and floodplains; and upland communities (Pruitt and 

34 TeWinkel 2007). Maternity colonies typically consist of 60 to 80 adult females (Whitaker and 

35 Brack 2002). Colonies occupy multiple trees for roosting and rearing young (Watrous 

36 et al. 2006) and, once established, usually return to the same areas each year (Pruitt and 

37 TeWinkel 2007). Nonreproductive females and males do not roost in colonies during the 

38 summer; they may remain near the hibernacula or migrate to summer habitat (Pruitt and 

39 TeWinkel 2007). High-quality summer habitat includes mature forest stands containing open 

40 subcanopies, multiple moderate- to high-quality snags, and trees with exfoliating bark (Farmer 

41 et al. 2002). In summer, bats forage for insects along forest edges, riparian areas, and in 

42 semiopen forested habitats. In the winter, Indiana bats rely on caves for hibernation. The 

43 species prefers hibernacula in areas with karst (limestone, dolomite, and gypsum), although it 

44 may also use other cave-like locations, such as mines.

45 The Indiana Bat Recovery Plan (Pruitt and TeWinkel 2007) indicates that Indiana bats are 

46 distributed across 36 of the 102 counties in Illinois. Twenty-two winter hibernacula (16 extant, 

47 4 of uncertain status, and 2 historic) are located throughout these counties. Additionally, 
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1 29 extant maternity colonies occur in Illinois, and adult males, nonreproductive females, or both 

2 have been captured during summer surveys within 26 of the 36 counties. None of these 

3 records identify Ogle County or any of the counties directly neighboring Ogle County as 

4 containing hibernacula or maternity colonies. For 2007, the FWS (2009) estimated that Illinois’s 

5 total population of Indiana bats was 54,095 individuals. According to more recent estimates 

6 based on FWS winter surveys conducted in January and February of 2013, the Illinois 

7 population of Indiana bats has increased by almost 2,000 over the past 6 years to 

8 55,956 individuals (King 2013).

9 The majority of the action area is developed or composed of unsuitable habitat types for 

10 hibernation, roosting, and foraging. The action area includes approximately 750 ac (300 ha) of 

11 land leased for agricultural use as well as some areas of mixed woodlands, meadows, and 

12 grasslands that could provide some marginal foraging habitat. The IDNR (2013) Natural 

13 Heritage Database indicates that the Indiana bat was last observed in Ogle County in 

14 April 2011. However, in March 2012, Exelon generated an IDNR Ecological Compliance 

15 Assessment Tool (EcoCAT) report that included Illinois Natural Heritage Database information 

16 on species that could potentially be affected by the proposed license renewal. This report did 

17 not indicate the presence of the Indiana bat on or in the vicinity of the Byron site 

18 (Exelon 2013a). The NRC staff did not identify any other records or other studies that suggest 

19 the occurrence of Indiana bats in the action area. Additionally, Exelon (2013a) indicates in its 

20 ER that it is not aware of observations or records of Indiana bat occurrences on plant property.

21 Given the available information, the NRC staff concludes that the Indiana bat is unlikely to occur 

22 within the action area.

23 Prairie Bush Clover (Lespedeza leptostachya)

24 The FWS listed the prairie bush clover as threatened in 1987 (52 FR 781). No critical habitat

25 has been designated for this species.

26 The prairie bush clover is an herbaceous perennial in the pea family (Fabaceae) that grows up 

27 to 1 m (3.2 ft) tall (Smith et al. 1988). The plant has clover-like leaves, pale pink to 

28 cream-colored flowers that bloom in mid-July, and silvery-green seed pods (FWS 2013f). 

29 Historically, the species spanned 27 counties in Minnesota, Wisconsin, Iowa, and Illinois in the 

30 tallgrass prairie region of the Upper Mississippi River Valley. Today, it is present in 24 counties 

31 and is most prevalent in northern Iowa and southern Minnesota (Smith et al. 1988). The 

32 species inhabits north-facing mesic to dry-mesic prairie slopes in soils with a mixture of loam, 

33 colluvium, sand, and gravel and occurs in populations ranging from tens to thousands of 

34 individuals (MDNR 2013). The IDNR (2013) Natural Heritage Database indicates that the 

35 prairie bush clover was last observed in Ogle County in the summer of 2009.

36 The March 2012 EcoCAT report indicated that the prairie bush clover may occur in the vicinity of 

37 the Byron site (Exelon 2013a). Although the action area includes approximately 150 ac of 

38 grasslands (Starke and Cox 2011), these grasslands do not include tallgrass prairie habitat (see 

39 Section 3.6 for a description of terrestrial resources). Additionally, Exelon (2012b) states in a 

40 biological evaluation submitted to the IDNR that the Byron site does not provide optimal habitat 

41 for the prairie bush clover and that it is not aware of observations or records of the species 

42 occurring on plant property.

43 Given the available information, the NRC staff concludes that the prairie bush clover is unlikely 

44 to occur within the action area.
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1 Eastern Prairie Fringed Orchid (Platanthera leucophaea)

2 The FWS listed the eastern prairie fringed orchid as threatened in 1989 (54 FR 39857). No 

3 critical habitat has been designated for this species.

4 The eastern prairie fringed orchid is a perennial herb that grows 8 to 40 in. (20 to 102 cm) tall 

5 and produces long clusters of up to 40 white flowers in early July (NatureServe 2013). It 

6 inhabits mesic prairie, wetlands, sedge meadows, marsh edges, and bogs with full sun and little 

7 to no woody encroachments (FWS 2013e). These orchids require hawkmoths for successful 

8 pollination, and seedling establishment requires a mycorrhizal relationship with soil fungus 

9 (Bowles 1999). Eastern prairie fringed orchids occur in the Eastern United States, Great Lakes 

10 states, and in Nova Scotia and Ontario, Canada. Illinois contained the largest historic 

11 populations of the species with populations at one time occurring in 33 counties (Bowles 1999). 

12 Today, about 20 populations are thought to exist in six counties near the Chicago region 

13 (Bowles 1999).

14 The IDNR (2013) Natural Heritage Database does not indicate that the eastern prairie fringed 

15 orchid has been observed in Ogle County, nor did the EcoCAT report indicate that the species 

16 occurs on or in the vicinity of the Byron site (Exelon 2013a). Additionally, Exelon (2012b) states 

17 in a biological evaluation submitted to the IDNR that the Byron site does not provide optimal 

18 habitat for the eastern prairie fringed orchid and that it is not aware of observations or records of 

19 the species occurring on plant property.

20 Given the available information, the NRC staff concludes that the eastern prairie fringed orchid 

21 is unlikely to occur within the action area.

22 Leafy Prairie Clover (Dalea foliosa)

23 The FWS listed the leafy prairie clover as endangered in 1991 (56 FR 19953). No critical 

24 habitat has been designated for this species.

25 The leafy prairie clover is a perennial wildflower in the legume family (Fabaceae) that grows 

26 1 to 2 ft (0.3 to 0.6 m) tall (DeMauro and Bowles 1996). The plant has alternate compound 

27 leaves, and small purple-to-pink flowers form in dense spikes at the top of stems in mid-to-late 

28 summer. Leafy prairie clovers grow in partial to full sun and thin rocky soils that are moist to 

29 slightly dry. The species occurs in northern Illinois, Tennessee, and Alabama. In Illinois, it is 

30 found in mesic dolomite prairie remnants along the Des Plains River, while in Tennessee and 

31 Alabama, it is found in cedar glades (DeMauro and Bowles 1996; FWS 2013c).

32 Given that the action area does not include any portion of the Des Plaines River, the leafy 

33 prairie clover is unlikely to be present. Additionally, the IDNR (2013) Natural Heritage Database 

34 does not indicate that the leafy prairie clover has been observed in Ogle County, and the 

35 EcoCAT report did not indicate that the species occurs on or in the vicinity of the Byron site 

36 (Exelon 2013a).

37 Given the available information, the NRC staff concludes that the leafy prairie clover is unlikely 

38 to occur within the action area.

39 3.8.1.3 Species and Habitats Under NMFS’s Jurisdiction

40 As discussed in Section 3.7, the Rock River does not contain marine or anadromous fish 

41 species. Therefore, no Federally listed species or habitats under NMFS’s jurisdiction occur 

42 within the action area.
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1 3.8.2 Species and Habitats Protected Under the Magnuson–Stevens Act

2 NMFS has not designated essential fish habitat in the Rock River. Therefore, this section does 

3 not contain a discussion of any species or habitats protected under the MSA. 

4 3.9 Historic and Cultural Resources

5 This section discusses the cultural background and the known historic and cultural resources 

6 found on and in the vicinity of Byron. The discussion is based on a review of historic and 

7 cultural resource surveys and other background information on the region surrounding Byron. 

8 In addition, a records search was performed via the Illinois Historic Preservation Agency (IHPA) 

9 (Pauketat 1993) to obtain the most updated information about historic and cultural resources in 

10 the region.

11 The Area of Potential Effect (APE) is the area at the Byron power plant site, the transmission 

12 lines up to the first substation, and immediate environs that may be affected by the license 

13 renewal decision and land-disturbing activities associated with continued reactor operations. 

14 For this analysis, the first substation (345-kV Byron switchyard) is located on the Byron site 

15 (Exelon 2013b). The APE may extend beyond the immediate environs in instances where 

16 land-disturbing maintenance and operations activities during the license renewal term or 

17 refurbishment activities could potentially have an effect. See Figure 3–3.

18 3.9.1 Cultural Background

19 Human occupation in the vicinity of Byron site is generally characterized according to the 

20 following chronological sequence (Pauketat 1993):

21  Paleo-Indian Period (12,000 – 10,000 before present (BP)),

22  Archaic Period (10,000 – 3,000 BP),

23  Woodland Period (3,000 – 1,100 BP),

24  Mississippian Period (1,100 – 400 BP (ca. A.D. 900 – 1600)), and

25  Protohistoric/Historic Period (400 – Present (ca. A.D. 1600 – Present)).

26 Paleo-Indian Period (12,000 – 10,000 BP)

27 The earliest evidence of people living in Illinois dates to the Paleo-Indian Period. Paleo-Indian 

28 sites are generally found upland or on river terraces and are characterized by specific types of 

29 projectile points (i.e., fluted Clovis and Folsom points) and stone tools such as gravers, 

30 scrapers, or large blades. These artifacts often occur in association with mastodon remains, 

31 suggesting a reliance on megafauna (e.g., mammoth, ground sloth, and saber-tooth tiger) for 

32 subsistence, along with plants, small game, birds, and amphibians. Social organization 

33 consisted of small, highly nomadic bands of hunter-gatherers, leaving Paleo-Indian sites with 

34 little detailed archaeological information (Neusius and Gross 2007; Pauketat 1993).

35 Archaic Period (10,000 – 3,000 BP)

36 The Archaic Period was a time of major climatic shifts as colder environments transitioned to 

37 warmer environments similar to modern conditions. In response to this shift, new technologies 

38 and subsistence strategies were developed during this time. The Archaic Period is often divided 

39 into early, middle, and late subperiods. The Early Archaic Period is characterized by a shift 

40 from nomadic to sedentary settlement patterns, with central base camps located on river 

41 terraces and smaller hunting camps located in upland areas. This subperiod also shows an 

42 increased reliance on wild plant foods, small game, and aquatic resources. The Middle Archaic 
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1 Period is characterized by an increased number of settlement sites on high stream terraces, 

2 which may reflect population increases. While subsistence and settlement patterns remained 

3 fairly similar to the Early Archaic Period, artifact assemblages suggest increased exploitation of 

4 aquatic resources as well as new artifacts such as pecked and ground stone tools used for 

5 intensive processing of nuts, banner stones that signaled the innovation of a new projectile 

6 technology called the atlatl or spear-thrower, and grooved axes. The Late Archaic Period is 

7 characterized by an increase in the number and size of settlement sites, which indicates an 

8 increase in population and a more sedentary lifestyle. New features of Late Archaic artifact 

9 assemblages, such as crude ceramic vessels, represent a shift toward increased reliance on 

10 horticulture as a subsistence strategy, although hunting and gathering would have continued 

11 (Fagan 2005; Neusius and Gross 2007; Pauketat 1993).

12 Woodland Period (3,000 – 1,100 BP)

13 The Woodland Period is also often divided into early, middle and late periods. However, the 

14 distinction between the early and middle period is not fixed. The Woodland Period is marked by 

15 an increase in more permanent settlements, changes in burial practices, increased cultivation of 

16 plants such as sunflowers and cucurbits (i.e., squashes, gourds, melons, etc.), and a rise in the 

17 manufacture and use of pottery (Fagan 2005). During the Middle Woodland Period, the large 

18 and complex Hopewell Culture emerged in the northeastern and midwestern United States, 

19 including Illinois. This culture is characterized by settlement in villages, increased reliance on 

20 intensive horticulture, burial mounds, and long-distance trade networks. These long-distance 

21 networks allowed the trade of exotic materials, such as marine shells from the Gulf Coast, 

22 obsidian from the Rocky Mountains, copper from Lake Superior, and mica from the Appalachian 

23 Mountains far outside their immediate locations. Evidence of the Illinois Hopewell culture is 

24 found primarily in the bluffs and floodplains of the Illinois River Valley. The burial mounds of this 

25 period often included central features, lined with logs, and filled with grave goods. Different 

26 burial treatments within the mounds point to social stratification within society, but through sex 

27 and age rather than hereditary lineage (Neusius and Gross 2007). The Late Woodland Period 

28 is characterized by an increase in settlement sites, which suggests a rise in population and/or a 

29 change in settlement patterns from large, centralized village sites to smaller, dispersed 

30 habitation sites. Late Woodland Period artifact assemblages are characterized by an increase 

31 in thin-walled plain ceramic types and stemmed and side-notched projectile points. The sudden 

32 appearance of very small, thin triangular projectile points between 1,300 and 1,400 BP indicates 

33 the invention of bow-and-arrow technology and suggests a corresponding change in hunting 

34 techniques (Fagan 2005).

35 Mississippian Period (1,100 – 400 BP (ca. A.D. 900 – 1600))

36 The Mississippian Period is characterized by major changes in settlement, subsistence patterns, 

37 and social structure. Large highly centralized chiefdoms with permanent settlement sites 

38 supported by numerous satellite villages emerged during this period. The platform mound, a 

39 new ceremonial earthen mound appeared in association with these permanent settlements. 

40 Platform mounds, burial mounds, and defensive structures, such as moats and palisades, were 

41 often constructed in clusters in settlements of this period and were common in the larger river 

42 valleys of the Midwest. Mississippian Period subsistence relied heavily on maize agriculture, as 

43 well as hunting and gathering. Long-distance trading increased and craft specialists produced 

44 highly specialized lithic and ceramic artifacts, beadwork and shell pendants (Fagan 2005).

45 In southern Wisconsin and northern Illinois, the emerging Mississippian culture was blended 

46 with the receding Woodland culture to produce the Oneota tradition. The Oneota were 

47 organized in permanent villages, produced unique ceramic artifacts, and relied on a mixed 

48 subsistence strategy of hunting and gathering, though cultivation of maize was practiced. Burial 
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1 traditions varied from the mounds of the Woodland Period to nonmounded cemeteries near their 

2 villages (Exelon 2013a; Neusius and Gross 2007).

3 Protohistoric/Historic Period (A.D. 1600 – Present)

4 The end of the Mississippian Period is characterized by severe social, political, and 

5 demographic changes that resulted from indirect and direct contact with Europeans. In 

6 particular, it is believed that the introduction of European infectious diseases such as smallpox, 

7 yellow fever, typhoid, and influenza severely decimated Native American populations, which had 

8 no immunity to these diseases. The spread of these diseases, which were fatal to large 

9 numbers of Native Americans, resulted in the widespread abandonment of villages and a 

10 concurrent collapse of Native American socioeconomic networks, such that by the time of 

11 widespread European contact and settlement, the Mississippian chiefdoms were gone 

12 (Fagan 2005). During this time period, Illinois was primarily populated with a confederation of 

13 tribes known as the Illinois, or Illiniwek, and the Miami tribe. During the 1700s and early 1800s, 

14 new tribes migrated to Illinois, including the Iroquois, Fox (Mesquakie), Ioway, Kickapoo, 

15 Mascouten, Piankashaw, Potawatomi, Sauk, Shawnee, Wea, and Winnebago. Competition for 

16 resources led to sporadic war among the Illinois and surrounding tribes for approximately the 

17 next 120 years (ISM 2002). French explorers and fur traders travelled down the Mississippi 

18 River into Illinois in the 17th century. Early European settlements were established along the

19 river systems by settlers seeking to profit from the fur trade. Illinois became part of the 

20 United States Northwest Territory at the close of the American Revolution and became a state 

21 in 1818 with Ogle County being formed in 1836. The area surrounding the Byron site has 

22 principally been used as agricultural land from this period onward (Ogle County 2014).

23 3.9.2 Historic and Cultural Resources

24 Historic and cultural resources include prehistoric era and historic era archaeological sites, 

25 historic districts, and buildings, as well as any site, structure, or object that may be considered 

26 eligible for listing on the National Register of Historic Places (NRHP). Historic and cultural 

27 resources also include traditional cultural properties that are important to a living community of 

28 people for maintaining their culture. “Historic property” is the legal term for a historic and/or 

29 cultural resource that is eligible for listing on the NRHP.

30 A review of databases maintained by the National Park Service (NPS) indicates that there are 

31 24 properties listed in the NRHP within Ogle County, including one that has been designated a 

32 National Historic Landmark (NHL) (NPS 2014a, 2014b). These historic properties reflect the 

33 historic cultural contexts for the Byron property and include historic buildings, structures, and 

districts dating from the mid-18th through mid-20th 34 centuries. However, none of the 24 historic 

35 properties are located within the boundaries of the Byron property. The closest NRHP-eligible 

36 site is in Byron, Illinois, approximately 4 mi (6 km) to the northeast.

37 In 1973 and 1974, Phase I and Phase II archaeological surveys were undertaken by the 

38 University of Wisconsin – Milwaukee for all lands purchased by ComEd for the proposed 

39 construction of Byron. These surveys identified eight archaeological sites and recommended 

40 fencing sites along the Rock River for protection if any construction would occur in their 

41 immediate area. Surveyors also recommended leaving a 15-meter (m) (50-ft) buffer between 

42 the other identified sites and any new construction (Birmingham and Fowler 1974). The Illinois 

43 State Historic Preservation Officer (SHPO) concurred that operation of Byron would not result in 

44 any significant impact on historic and cultural sites in the area (Exelon 2013b).

45 A search of the Illinois State Archaeological Site Files, a database maintained by the Illinois 

46 SHPO, by NRC staff identified four cultural resources within the current confines of the Byron 
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1 site, with one site immediately adjacent to the property boundary. All sites are ineligible for the 

2 NRHP. These sites are identified in Table 3–15.

3 Table 3–15. Cultural Resources Within the Byron Site

Site On the Byron Site Description NRHP

11OG153 No Archaic dwelling and/or hearth Ineligible

11OG155 Yes

Prehistoric; scattered surface 

finds of projectile points, scrapers, 

and flakes

Ineligible

11OG156 Yes

Prehistoric; scattered surface 

finds of projectile points, scrapers, 

and flakes

Ineligible

11OG157 Yes

Prehistoric; scattered surface 

finds of projectile points, scrapers, 

and flakes

Ineligible

11OG158 Yes

Prehistoric; scattered surface 

finds of projectile points, scrapers, 

and flakes

Ineligible

Source: Illinois Inventory of Archaeological Sites, ISM 2014

4 3.10 Socioeconomics

5 This section describes current socioeconomic factors that have the potential to be directly or 

6 indirectly affected by changes in operations at Byron. Byron, and the communities that support 

7 it, can be described as a dynamic socioeconomic system. The communities supply the people, 

8 goods, and services required to operate the nuclear power plant. Power plant operations, in 

9 turn, supply wages and benefits for people and dollar expenditures for goods and services. The 

10 measure of a community’s ability to support Byron operations depends on its ability to respond 

11 to changing environmental, social, economic, and demographic conditions.

12 3.10.1 Power Plant Employment and Expenditures

13 The socioeconomics region of influence (ROI) is defined by the areas where Byron employees 

14 and their families reside, spend their income, and use their benefits, thus affecting the economic 

15 conditions of the region. Exelon Generation employs a permanent workforce of approximately 

16 870 employees and 20 long-term contract employees (Exelon 2013a). Approximately 

17 82 percent of Byron employees reside in a three-county area in northern Illinois in Lee, Ogle, 

18 and Winnebago Counties. Most of the remaining 18 percent of the workforce are spread among 

19 18 other counties in Illinois and 5 counties outside of Illinois, with numbers ranging from 1 to 

20 53 employees per county (Exelon 2013a). Given the residential locations of Byron employees, 

21 the most significant effects of plant operations are likely to occur in Ogle, Lee, and Winnebago 

22 counties. Table 3–16 summarizes the Byron workforce geographic distribution. The focus of 

23 the socioeconomic impact analysis in this SEIS is, therefore, on the impacts of continued Byron 

24 operations on these three counties, also termed the ROI.
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1 Table 3–16. Exelon Generation Employees Residence by County

County Number of 

Employees

Percentage of 

Total

DeKalb 25 3

Lee 115 13

Ogle 352 41

Whiteside 52 6

Winnebago 243 28

Other 

counties 80 9 

Total 867 100

Source: Exelon 2013b

2 Exelon purchases goods and services to facilitate Byron operations. While specialized 

3 equipment and services are procured from a wider region, some proportion of the goods and 

4 services used in plant operations are acquired from within the ROI. These transactions fuel a 

5 portion of the local economy, as jobs are provided and additional local purchases are made by 

6 plant suppliers.

7 The Byron units are on staggered 18-month refueling intervals. During refueling outages, site 

8 employment typically increases by an average of 1,400 temporary workers for approximately 

9 20 days (Exelon 2013a). Outage workers are drawn from all regions of the country; however, 

10 the majority would be expected to come from Illinois, Wisconsin, and other Midwestern States.

11 3.10.2 Regional Economic Characteristics

12 This section presents information on employment and income in the Byron socioeconomic ROI. 

13 The three-county ROI is predominantly rural and agricultural. Agricultural and forested land 

14 comprises the majority of the land use in Ogle, Lee, and Winnebago Counties. Urban 

15 developed land makes up only about 8, 7, and 25 percent of total land area of each county, 

16 respectively (NASS 2012b).

17 3.10.2.1 Employment and Income

18 From 2000 to 2012, the labor force in the Byron ROI decreased approximately 4 percent to just 

19 over 183,000. The number of employed persons declined by about 10.6 percent over the same 

20 period, to approximately 163,000. Consequently, the number of unemployed people in the ROI 

21 has increased nearly 135 percent in the same period, to over 11,700, or about 6.7 percent of the 

22 current workforce—up from 4.5 percent in 2000 (BLS 2014).

23 According to the U.S. Census Bureau’s (USCB’s) 2008–2012 American Community Survey 

24 5-Year Estimates, the educational, health, and social services industry represented the largest 

25 employment sector in the socioeconomic ROI (22.5 percent) followed by manufacturing 

26 (21 percent) and retail (11.4 percent). A list of employment by industry in each county of the 

27 ROI is provided in Table 3–17.
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1 Table 3–17. Employment by Industry in the Byron ROI (5-year estimates 2008–2012)

Industry Lee Ogle Winnebago Total Percent

Total employed civilian workers 16,202 25,827 131,758 173,787 –

Agriculture, forestry, fishing, hunting, and 

mining 463 606 648 1,717 1.0

Construction 851 1,834 6,525 9,210 5.3

Manufacturing 3,127 4,360 28,961 36,448 21.0

Wholesale trade 564 875 3,104 4,543 2.6

Retail trade 1,731 3,087 14,929 19,747 11.4

Transportation, warehousing, and utilities 1,074 2,420 7,585 11,079 6.4

Information 220 503 2,243 2,966 1.7

Finance, insurance, 

real estate, rental, and leasing 644 1,237 6,466 8,347 4.8

Professional, scientific, management, 

administrative, and waste management 

services

988 1,924 10,314 13,226 7.6

Educational, health, and social services 3,975 5,014 30,097 39,086 22.5

Arts, entertainment, recreation, 

accommodation, and food services 1,143 1,709 10,169 13,021 7.5

Other services (except public administration) 632 1,342 6,938 8,912 5.1

Public administration 790 916 3,779 5,485 3.2

Source: USCB 2014a

2 Major employers in Ogle County, the county in which Byron is located, are listed in Table 3–18. 

3 Exelon Generation is shown as the largest employer in the county.

4 Estimated income information for the Byron ROI is presented in Table 3–19. According to the 

5 USCB’s 2008–2012 American Community Survey 5-Year Estimates, people living in the 

6 three-county ROI had median household and per capita incomes below the State average. 

7 Winnebago County has the highest percentages of persons (17 percent) living below the official 

8 poverty level when compared to the other two counties and the State of Illinois as a whole. Lee

9 and Ogle Counties had 10 percent, respectively, and the State of Illinois as a whole had 

10 13.7 percent. The percentage of families living below the poverty level in Lee and Ogle 

11 Counties (7.4 percent, respectively) was lower than the percentage of families in Winnebago 

12 County and the State of Illinois as a whole (12.8 percent and 10 percent, respectively) 

13 (USCB 2014a).
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1 Table 3–18. Major Employers in Ogle County in 2012

Employer (City or Village) Industry/Product/Service Number of 

Employees

Exelon Generation (Byron) Electric utility, nuclear power generation 870

Rochelle Foods/Hormel (Rochelle) Pork products 760

E.D. Etnyre & Co. (Oregon) Road construction equipment manufacturing 350

Pine Crest Manor (Mt. Morris) Nursing care facility 312

Rochelle Schools (Rochelle) Education 305

Rochelle Hospital (Rochelle) Health care 265

Veolia (Davis Junction) Solid waste disposal/landfill operation 251

Byron Schools (Byron) Education 250

Sara Lee (Rochelle) Cold storage, sales & marketing 235

Americold (Rochelle) Frozen foods storage & distribution 232

Quality Metal Finishing, Inc. (Byron) Metal plating/finishing 210

Woods Equipment Co. (Oregon)

Manufacturing of attachments and 

replacement parts for agricultural, landscape 

and light construction markets

200

PNC, Inc. (Polo)

Manufacturer of custom electromagnet 

solenoid coils and wiring harnesses for the 

automotive and hydraulic industry

200

Silgan Containers (Rochelle) Provider of metal food packaging products 200

Village of Progress (Oregon) Social service organization 169

Austin-Westran (Byron) Metal cabinets/metal fabrication 155

County of Ogle (Oregon) County government 150

Bay Valley Foods (Rochelle) Labeling, warehousing, distribution of 

shelf-stable foods 150

Del Monte, Inc. (Rochelle) Warehousing and distribution of canned food 

products 150

Ryder Logistics (Rochelle) Warehousing and distribution of 

refrigerated/frozen food products 135

City of Rochelle (Rochelle) Municipal government 125

The Neighbors (Byron) Nursing care facility 115

Rochelle Nursing Home (Rochelle) Nursing care facility 115

Source: Ogle County 2012 
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1 Table 3–19. Estimated Income Information for the Byron ROI (5-year estimates 2008–2012)

Lee Ogle Winnebago Illinois

Median household income (dollars)(a) 50,342 55,590 47,573 56,853

Per capita income (dollars)(a) 25,484 26,331 24,404 29,519

Individuals living below the poverty level (percent) 10.0 10.0 17.0 13.7

Families living below the poverty level (percent) 7.4 7.4 12.8 10.0

(a) In 2012 inflation adjusted dollars

Source: USCB 2014a

2 3.10.2.2 Unemployment

3 According to the USCB’s 2008–2012 American Community Survey 5-Year Estimates, the 

4 unemployment rates were: Lee County, 9.2 percent; Ogle County, 9.8 percent; and Winnebago 

5 County, 12 percent. Comparatively, the State of Illinois’s unemployment rate during this same 

6 time period was 9.9 percent (USCB 2014a).

7 3.10.3 Demographic Characteristics

8 According to the 2010 Census, an estimated 248,387 people lived within 20 mi (32 km) of 

Byron, which equates to a population density of 198 persons per mi2 9 (Exelon 2013a). This 

10 translates to a Category 4, “least sparse” population density using the generic environmental 

impact statement (GEIS) measure of sparseness (greater than or equal to 120 persons per mi2 11

12 within 20 mi). An estimated 1,247,087 people live within 50 mi (80 km) of Byron with a 

population density of 159 persons per mi2 13 (Exelon 2013a). This translates to a Category 3 

14 density, using the GEIS measure of proximity (one or more cities with 100,000 or more persons 

and less than 190 persons per mi2 15 within 50 mi (80 km)). The nearest city with a population 

16 greater than 100,000 is Rockford, Illinois (17 mi (27 km) northeast), with a 2010 population of 

17 152,871 (USCB 2014b). Therefore, Byron is located in a high population area based on the 

18 GEIS sparseness and proximity matrix.

19 Table 3–20 shows population projections and percent growth from 1970 to 2060 in the 

20 three-county Byron ROI. The population in the ROI has increased over the previous 2 decades 

21 (2000 and 2010). Based on State forecasts, the population is expected to continue to increase 

22 at a moderate to high rate due in part to the close proximity of the ROI to Chicago. Population 

23 projections for years 2020 and 2030 shown in the table were developed by the Illinois 

24 Department of Commerce and Economic Opportunity (DCEO) and are based on projected 2000 

25 population census estimates (see Table 3–21). As a result, the projected 2020 and 2030 

26 population estimates may be overstated, as actual population data from the 2000 and 2010 

27 decennial census were lower than the 2000 and 2010 population estimates projected by the 

28 DCEO.
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1 Table 3–20. Population and Percent Growth in Byron ROI Counties 1970–2010, 2012 

2 (estimated), and Projected for 2020–2060

Year

Lee County Ogle County Winnebago County

Population Percent 

growth Population Percent growth Population Percent growth

1970 37,947 – 42,876 – 246,623 –

1980 36,328 −4.3 46,338 8.1 250,884 1.7

1990 34,392 −5.3 45,957 −0.8 252,913 0.8

2000 36,062 4.9 51,032 11.0 278,418 10.1

2010 36,031 −0.1 53,497 4.8 295,266 6.1

2012* 35,037 −2.8 52,848 −1.2 292,069 −1.1

2020 37,939 3.8 59,230 8.3 337,049 9.7

2030 38,923 2.6 63,765 7.7 359,900 6.8

2040 38,971 0.1 66,245 3.9 377,172 4.8

2050 39,645 1.7 69,943 5.6 400,439 6.2

2060 40,319 1.7 73,640 5.3 423,705 5.8

Sources: Decennial population data for 1970–2010, and estimated 2012 (USCB 2014b); projections for 

2020–2030 by Illinois Department of Commerce and Economic Opportunity (DCEO 2012); 2040–2060 calculated

* Bold indicates most recent population estimate from the U.S. Census.

3 Table 3–21. Illinois Department of Commerce and Economic Opportunity (DCEO) 

4 Population Projections for 2000–2030

Year

Lee County Ogle County Winnebago County

Population

Percent 

growth Population

Percent 

growth Population

Percent 

growth

2000 36,118 – 51,119 – 278,902 –

2010 36,554 1.2 54,704 7.0 307,349 10.2

2020 37,939 3.8 59,230 8.3 337,049 9.7

2030 38,923 2.6 63,765 7.7 359,900 6.8

Source: DCEO 2012

5 The 2010 Census demographic profile of the three-county region of influence population is 

6 presented in Table 3–22. According to the 2010 Census, minorities (race and ethnicity 

7 combined) comprised 23.7 percent of the total three-county population. The largest minority 

8 populations in the three-county ROI are Hispanic or Latino (10.1 percent) and Black or 

9 African-American (9.8 percent).
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1 Table 3–22. Demographic Profile of the Population in the Byron ROI in 2010

Lee Ogle Winnebago ROI

Total Population 36,031 53,497 295,266 384,794

Race (percent of total population, Not-Hispanic or Latino)

White 88.3 88.6 72.5 76.3

Black or African-American 4.7 0.9 12.0 9.8

American Indian & Alaska Native 0.1 0.2 0.2 0.2

Asian 0.7 0.5 2.3 1.9

Native Hawaiian & Other Pacific Islander 0.0 0.0 0.0 0.0

Some other race 0.1 0.0 0.1 0.1

Two or more races 1.0 0.9 2.0 1.8

Ethnicity

Hispanic or Latino 1,802 4,741 32,177 38,720

Percent of total population 5.0 8.9 10.9 10.1

Minority population (including Hispanic or Latino ethnicity)

Total minority population 4,207 6,072 81,070 91,349

Percent minority 11.7 11.4 27.5 23.7

Source: USCB 2014c

2 3.10.3.1 Transient Population

3 Within 50 mi (80 km) of Byron, colleges and recreational opportunities attract daily and seasonal 

4 visitors who create a demand for temporary housing and services. In 2013, approximately 

5 27,700 students attended colleges and universities within 50 mi (80 km) of Byron (NCES 2013).

6 Based on the 2008−2012 American Community Survey (ACS) estimates, approximately 

7 18,800 seasonal housing units are located within 50 mi (80 km) of Byron. Of those, 1,168 were 

8 located in the Byron ROI. Table 3–23 presents information about seasonal housing for the 

9 counties located all or partly within 50 mi (80 km) of Byron.
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1 Table 3–23. 2007–2011 Estimated Seasonal Housing in Counties Located Within 50 mi 

2 (80 km) of Byron

County(a) Total Seasonal Housing 

Units

Vacant Housing Units: for 

Seasonal, Recreational, or 

Occasional Use

Percent

Illinois

Boone 19,909 38 0.2

Bureau 15,712 219 1.4

Carroll 8,432 819 9.7

DeKalb 40,932 305 0.7

Henry 22,135 118 0.5

Jo Daviess 13,560 2,797 20.6

Kane 181,587 399 0.2

Kendall 40,002 82 0.2

La Salle 49,924 731 1.5

Lee 15,049 373 2.5

McHenry 116,015 1,136 1.0

Ogle 22,539 321 1.4

Stephenson 22,076 427 1.9

Whiteside 25,742 233 0.9

Winnebago 125,928 474 0.4

County Subtotal 719,542 8,472 1.2

Iowa

Clinton 21,753 172 0.8

Jackson 9,400 465 4.9

County Subtotal 31,153 637 2.0

Wisconsin

Green 15,857 316 2.0

Lafayette 7,218 140 1.9

Rock 68,369 1,105 1.6

Walworth 51,441 8,146 15.8

County Subtotal 142,885 9,707 6.8

Total 893,580 18,816 2.1

(a) Counties within a 50 mi (80 km) radius of Byron

Source: USCB 2014d
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1 3.10.3.2 Migrant Farm Workers

2 Migrant farm workers are individuals whose employment requires travel to harvest agricultural 

3 crops. These workers may or may not have a permanent residence. Some migrant workers 

4 follow the harvesting of crops, particularly fruit, throughout rural areas of the United States. 

5 Others may be permanent residents near Byron and travel from farm to farm harvesting crops.

6 Migrant workers may be members of minority or low-income populations. Because they travel 

7 and can spend a significant amount of time in an area without being actual residents, migrant 

8 workers may be unavailable for counting by census takers. If uncounted, these workers would 

9 be “underrepresented” in USCB minority and low-income population counts.

10 Information about migrant farm and temporary labor was collected in the 2007 Census of 

11 Agriculture. Table 3–24 supplies information about migrant farm workers and temporary farm 

12 labor (less than 150 days) within 50 mi (80 km) of Byron. According to the 2007 Census of 

13 Agriculture, approximately 14,100 farm workers were hired to work for less than 150 days and 

14 were employed on 4,689 farms within 50 mi (80 km) of Byron. The county with the highest 

15 number of temporary farm workers (1,127) on 219 farms was McHenry County, Illinois 

16 (NASS 2012a).

17 In the 2002 Census of Agriculture, farm operators were asked for the first time whether or not 

18 they hired migrant workers—defined as a farm worker whose employment required travel—to 

19 do work that prevented the migrant workers from returning to their permanent place of residence 

20 the same day. A total of 182 farms, in the 50-mi radius of Byron, reported hiring migrant 

21 workers in the 2007 Census of Agriculture. DeKalb County, Illinois, reported the most farms 

22 with migrant farm labor (16 farms) (NASS 2012a).
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1 Table 3–24. Migrant Farm Workers and Temporary Farm Labor in Counties Located 

2 within 50 mi (80 km) of Byron

County(a)

Number of Farms 

with Hired Farm 

Labor(b)

Number of Farms 

Hiring Workers for 

Less Than 

150 Days (b)

Number of Farm 

Workers Working 

for Less Than 

150 Days (b)

Number of 

Farms 

Reporting 

Migrant Farm 

Labor(b)

Illinois

Boone 121 97 274 12

Bureau 321 278 786 4

Carroll 202 165 382 9

DeKalb 269 223 1,014 16

Henry 423 344 808 15

Jo Daviess 214 163 449 4

Kane 231 172 798 13

Kendall 111 94 371 11

La Salle 402 338 760 9

Lee(c) 242 203 462 10

McHenry 284 219 1,127 15

Ogle(c) 293 258 629 7

Stephenson 286 209 560 11

Whiteside 316 273 739 9

Winnebago(c) 146 125 364 1

County 

Subtotal 3,861 3,161 9,523 146

Iowa

Clinton 411 341 1,021 1

Jackson 234 190 489 2

County 

Subtotal 645 531 1,510 3 

Wisconsin

Green 403 284 662 6

Lafayette 377 267 718 13

Rock 348 266 933 8

Walworth 252 180 747 6

County 

Subtotal 1,380 997 3,060 33

Total 5,886 4,689 14,093 182
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County(a)

Number of Farms 

with Hired Farm 

Labor(b)

Number of Farms 

Hiring Workers for 

Less Than 

150 Days (b)

Number of Farm 

Workers Working 

for Less Than 

150 Days (b)

Number of 

Farms 

Reporting 

Migrant Farm 

Labor(b)

(a) Counties within 50 mi (80 km) of Byron with at least one block group located within the 50-mi radius

(b) Table 7. Hired farm Labor—Workers and Payroll: 2007

(c) Counties in the socioeconomic ROI

Source: 2007 Census of Agriculture — County Data (NASS 2012a)

1 3.10.4 Housing and Community Services

2 This section presents information regarding housing and local public services, including 

3 education and water supply.

4 3.10.4.1 Housing

5 Table 3–25 lists the total number of occupied and vacant housing units, vacancy rates, and 

6 median value in the ROI. Based on the USCB’s 2008–2012 ACS 5-Year Estimates, there were 

7 nearly 164,000 housing units in the socioeconomic region, of which nearly 148,000 were 

8 occupied. The median values of owner-occupied housing units in the ROI range from $113,000 

9 in Lee County to about $151,000 in Ogle County. The vacancy rate also varied considerably 

10 between the three counties, from 8 percent in Ogle County to 10.2 percent in Winnebago 

11 County (USCB 2014e).

12 Table 3–25. Housing in the Byron ROI (2008−2012, 5-year estimate)

Lee

County

Ogle

County

Winnebag

o County ROI

Total housing units 15,049 22,539 125,928 163,516

Occupied housing units 13,686 20,728 113,119 147,533

Total vacant housing units 1,363 1,811 12,809 15,983

Percent total vacant 9.1 8.0 10.2 9.8

Owner occupied units 10,195 15,496 76,421 102,112

Median value (dollars) 113,000 151,400 127,500 129,679

Owner vacancy rate (percent) 1.3 1.8 1.2 1.3

Renter occupied units 3,491 5,232 36,698 45,421

Median rent (dollars/month) 622 669 721 707

Rental vacancy rate (percent) 5.4 7.1 5.2 5.4

Source: USCB 2014e
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1 3.10.4.2 Education

2 There are six public school districts in Lee County with 15 schools and an average daily total 

3 enrollment of approximately 4,600 students during the 2010–2011 school year. Winnebago 

4 County has 11 public school districts with 95 schools and had approximately 38,600 students. 

5 In Ogle County, the county in which Byron is located, there are 10 public school districts with 

6 27 schools and over 9,600 students (ISBE 2014).

7 3.10.4.3 Public Water Supply

8 Table 2.9-1 of Exelon’s ER (Exelon 2013a) lists the largest public water suppliers in Ogle, Lee, 

9 and Winnebago Counties and provides water use and supply information for those suppliers. 

10 The discussion of public water supply systems is limited to major municipal water systems in the 

11 local area. Most of the water for domestic, municipal, and industrial use in the region comes 

12 from groundwater. Information about municipal water suppliers close to Byron, their maximum 

13 design yields, reported annual average usage, and population served are presented in 

14 Table 3–26. All major public water suppliers in Ogle, Lee, and Winnebago Counties obtain their 

15 supplies from groundwater. Currently, there is excess capacity in every major public water 

16 system in the three counties. Byron gets potable water from two onsite groundwater wells not 

17 connected to a public water system.

18 Table 3–26. Local Public Water Supply Systems (in million gallons per day (mgd))

Public Water System County Usage 

(mgd)

Pump 

Capacity 

(mgd)

Population 

Served(a)

Dixon Lee 2.2 12.0 16,100

Woodhaven Lee 0.4 2.1 4,100

Byron Ogle 0.6 2.3 4,101

Oregon Ogle 0.4 3.1 4,101

Rochelle Ogle 2.7 7.2 9,850

Cherry Valley Winnebago 0.6 6.2 5,000

Illinois American – South Beloit Winnebago 0.7 NA 6,750

Loves Park Winnebago 3.0 6.9 22,476

North Park Public Water District Winnebago 3.5 18.1 35,737

Rockford Winnebago 25.6 125.0 155,000

Rockton Winnebago 0.8 6.2 7,440

NA = Not available

(a) Safe Drinking Water Search for the State of Illinois (EPA 2014b)

Sources: EPA 2014b; Exelon 2013a
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1 3.10.5 Tax Revenues

2 Property taxes paid by Exelon Generation for Byron are generally determined using the 

3 equalized assessed value (EAV) set by the county assessor, and the tax levy and rates set by 

4 each taxing district. Periodically, Exelon Generation enters into negotiations (which may result 

5 in a “settlement agreement”) with Ogle County and the other taxing districts to set the EAV for 

6 Byron. Negotiations can consider, but are not limited to, property valuation approaches, tax 

7 “triggers” (or limits), and payments in addition to taxes (PIAT). Exelon’s last settlement 

8 agreement for Byron was signed on November 8, 2008, and covered tax years 2005 through 

9 2011, which included negotiated triggers or tax limits. If tax levies exceeded these negotiated 

10 triggers, Exelon Generation could reduce Byron’s property tax obligation by the amounts in 

11 excess of the triggers. Exelon Generation also agreed to make additional payments (PIAT) to 

12 specific tax recipients. These payments are not considered tax payments in the traditional 

13 sense. They have fewer limitations for use and provide additional benefits for recipients. In 

14 accordance with the 2008 settlement agreement, Exelon Generation made two PIAT payments 

15 of $2,302,000 each; one in 2008 and the other in 2010 (Exelon 2013b). Table 3–27 lists the

16 PIAT payments and their recipients.

17 Exelon Generation and the taxing bodies have not entered into another settlement agreement, 

18 although negotiations have begun. Negotiations are in the early stages, and PIAT payments 

19 may be included as part of any future settlement agreement. Exelon Generation expects the 

20 recipients would remain the same as those listed in Table 3–27 because those are the taxing 

21 institutions that levy tax on the two power block Property Index Numbers (PINs). The settlement 

22 agreements have historically only settled the EAV for the two power block PINs (Exelon 2013b).

23 Table 3–27. PIAT Payments and Recipients, 2008 and 2010

Tax Recipients Dollars Percent of 

Total

Ogle County 270,863 11.8

Byron Fire Protection District 166,564 7.2

Byron Library District 56,659 2.5

Byron Museum District 6,256 0.3

Byron Forest Preserve District 127,339 5.5

Oregon Park District 147,137 6.4

Rockvale Township 12,888 0.6

Rockvale Township Road District 30,192 1.3

Rock Valley College 90,874 3.9

Byron Community Unit School District No. 226 1,346,079 58.5

Kishwaukee College 4,926 0.2

Oregon Community Unit School District No. 220 42,223 1.8

Total 2,302,000 100.0

Source: Exelon 2013a
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1 The Ogle County Assessor set the EAV for the 2012 tax year at $499 million, which is more 

2 than 4 percent higher than the EAV set under the existing settlement agreement. Exelon 

3 Generation believes the higher EAV overvalues Byron because an independent appraiser set 

4 the 2012 value of the station at $1.85 billion, which equates to an EAV of approximately 

5 $296.9 million. On this basis, Exelon Generation appealed the 2012 assessment to the Ogle 

6 County Board of Review. Upon an unfavorable ruling by the Board of Review, Exelon 

7 Generation then appealed the assessment to the Illinois Property Tax Appeal Board. The 

8 company will continue to negotiate with the taxing bodies to reach a settlement agreement, and 

9 in its absence, will appeal any assessment that does not reflect a valuation of the plant that they 

10 believe is fair (Exelon 2013b). 

11 Pending the outcome of such actions, Exelon Generation has paid the tax assessed for 2012 

12 (an increase of more than $2 million over the prior year, see Table 3–28). This increase was 

13 based on the EAV set by the assessor for the two combined power block PINs. Exelon 

14 Generation actually pays property taxes on 48 land parcels or PINs at Byron. The total taxes 

15 paid by Exelon Generation include taxes for all of the PINs (Exelon 2013b).

16 As previously discussed, the Ogle County Treasurer collects the property tax payment and 

17 disperses it to various institutions within the county to partially fund their operating budgets. 

18 These include, but are not limited to, the Byron Forest Preserve, the Oregon Park District, the 

19 Rock Valley Community College 511, the Byron Unit 226 School District, the Byron Fire District, 

20 the Byron Library District, Ogle County, and Rockvale Township (Exelon 2013a). From 2008 

21 through 2012, Ogle County’s total adjusted property tax levies ranged from approximately 

22 $111.3 to $116.6 million annually (see Table 3–28). From 2008 through 2012, Byron’s total 

23 property tax payments (after tax triggers and not including PIAT payments) represented 26.0 to 

24 28.3 percent of Ogle County’s total adjusted property tax levy (see Table 3–28).

25 Table 3–28. Property Tax Payment Comparison, All Taxing Districts Combined

Year

Total Combined Taxing 

District Levy—Ogle County 

(after adjustments)

(millions of dollars)

Byron Property Tax Payment 

(after tax triggers have been 

applied and not including PIAT 

payments)

(millions of dollars)

Byron Payment as 

Percent of Total District 

Levy

(percent)

2008 111.3 29.1 26.1

2009 113.8 29.6 26.0

2010 114.5 30.2 26.4

2011 113.9 30.8 27.0

2012 (a)116.6 (a)33.0 (a)28.3

(a) Preliminary data

Sources: Exelon 2013a, 2013b

26 The recipient of the largest percentage of Byron’s property tax payment is the Byron Unit 226 

27 School District (Exelon 2013a). Table 3–29 compares Byron’s property tax payments (after tax 

28 triggers and not including PIAT payments) to the Byron Unit 226 School District’s adjusted total 

29 property tax levies. From 2008 through 2012, Byron’s property tax payments to the school 

30 district represented 72.9 to 75.6 percent of the school district’s total adjusted property tax levies 

31 (see Table 3–29).
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1 Table 3–29. Property Tax Payment Comparison, All Taxing Districts Combined

Year

Total Byron Unit 226 

School District Levy 

(after adjustments) 

(millions of dollars)

Byron Unit 226 School District 

Portion of Byron Property Tax 

Payment (after tax triggers have 

been applied and not including PIAT 

payments)

(millions of dollars)

Byron Payment as 

Percent of Total District 

Levy

(percent)

2008 22.4 16.3 72.9

2009 22.7 16.7 73.3

2010 23.1 17.0 73.5

2011 23.2 17.2 74.3

2012 (a)24.5 (a)18.5 (a)75.6

(a) Preliminary data

Sources: Exelon 2013a, 2013b

2 Exelon Generation pays property taxes directly to Ogle County in accordance with tax bills 

3 received from Ogle County each year. Each bill shows all of the taxing bodies that are imposing 

4 a tax on each tax parcel. As the Byron property is large, some of its tax parcels fall within 

5 multiple taxing districts. Exelon Generation, however, has no control over how the tax money is 

6 allocated to the respective taxing districts. Each district has the ability to levy against all 

7 taxpayers within its respective district according to its own charter and according to State law. 

8 The Ogle County Treasurer then allocates the tax money according to predetermined levies 

9 once all taxes have been collected (Exelon 2013b).

10 The following tables show the total levy for each taxing body and the amount paid by Exelon 

11 Generation to each taxing body. The tables also show the percentage of total revenue 

12 represented by Exelon Generation’s tax payment for the tax years 2011 and 2012 (see 

13 Tables 3–30 and 3–31, respectively). The 2012 data are preliminary when submitted by the 

14 applicant, and the total levies for any one of the taxing bodies within Ogle County may change 

15 when the tax year closes (Exelon 2013b).

16 Although variations in tax levies are not completely under its control, Exelon Generation expects 

17 that Byron’s annual property tax payments will remain relatively constant through the license 

18 renewal period. In 1998, Byron replaced the Unit 1 steam generators. Because the 

19 replacement was considered one-for-one, the Station’s assessed value was unaffected. Exelon 

20 expects that any future one-for-one replacement projects will also not affect the station’s 

21 assessed value (Exelon 2013a).
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1 Table 3–30. 2011 Property Tax Payment Comparison, Each Taxing District Individually

Taxing Body

Total Taxing 

District Levy

(dollars)

Taxing District 

Portion of Byron 

Property Tax 

Payment

(dollars)

Byron Payment 

as Percent of 

Taxing District 

Levy

(percent)

Rockvale Township Road District 439,398.38 412,078.70 94

Rockvale Township 162,893.90 147,867.78 91

Oregon Park District 2,426,968.19 1,945,577.49 80

Byron Library District 985,733.24 790,179.58 80

Byron Fire District 2,847,882.53 2,137,067.08 75

Byron Forest Preserve 2,235,104.08 1,664,691.42 75

Byron School Unit 226 23,175,260.74 17,219,124.59 74

Byron Museum District 107,847.70 80,314.40 74

Rock Valley Community College 511 3,996,316.29 2,131,800.53 53

Ogle County 10,895,856.26 3,500,490.42 32

Oregon School Unit 220 9,954,055.80 608,129.98 6

Kishwaukee College 523 2,178,105.74 70,351.06 3

Marion Township Road 280,324.97 7,001.20 2

Marion Township 202,895.79 4,815.41 2

Stillman Valley Fire District 564,747.94 6,558.42 1

Byron Park District 535,352.10 5,599.27 1

Meridian Unit 223 7,668,245.10 28,676.18 <1

Julia Hull District Library 216,840.52 746.90 <1

Oregon Fire District 393,225.48 511.33 <1

City of Byron 680,358.62 789.59 <1

Byron Township Road 531,168.42 359.68 <1

Byron Township 197,888.03 121.79 <1

Source: Exelon 2013a
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1 Table 3–31. 2012 Property Tax Payment Comparison, Each Taxing District Individually

Taxing Body

Total Taxing 

District Levy

(dollars)

Taxing District 

Portion of Byron 

Property Tax 

Payment

(dollars)

Byron Payment 

as Percent of 

Taxing District 

Levy

(percent)

Rockvale Township Road District 473,936.19 433,301.95 91

Rockvale Township 170,402.82 155,781.07 91

Oregon Park District 2,592,707.40 2,053,432.47 79

Byron Library District 1,100,021.40 832,826.26 76

Byron Fire District 2,849,570.86 2,173,799.08 76

Byron Forest Preserve 2,723,877.90 2,063,496.61 76

Byron School Unit 226 24,531,412.11 18,540,024.03 76

Byron Museum District 107,904.13 81,743.99 76

Rock Valley Community College 511 3,983,228.58 2,186,116.75 55

Ogle County 11,050,901.32 3,696,958.55 33

Oregon School Unit 220 9,727,868.75 636,845.75 7

Kishwaukee College 523 2,408,561.88 81,556.77 3

Marion Township Road 275,794.50 6,764.70 2

Marion Township 203,166.03 4,835.00 2

Stillman Valley Fire District 546,071.62 6,333.17 1

Byron Park District 537,766.04 5,622.09 1

Meridian Unit 223 7,638,510.57 28,042.48 <1

Julia Hull District Library 227,365.20 721.32 <1

Oregon Fire District 407,275.39 556.99 <1

City of Byron 664,602.29 814.93 <1

Byron Township Road 548,577.95 366.86 <1

Byron Township 205,197.50 141.50 <1

Source: Exelon 2013a

2 3.10.6 Local Transportation

3 Major freeways serving Ogle County include interstates I-39 and I-88. Other major roadways 

4 serving the county are north/south state routes 2, 26, and 251, U.S. Highway 52, and east/west 

5 state routes 38, 64, and 72. Road access to Byron is via German Church Road (also known as 

6 County Highway 2), which runs northeast-southwest. Byron has two access roads, a northern 

7 entrance and a southern entrance, both of which intersect German Church Road approximately 

8 3 to 4 mi (5 to 6 km) southwest of the City of Byron. The northern access road provides primary 

9 access to the site for employees. In the City of Byron, German Church Road intersects County 

10 Highway 33 and State route Illinois (IL) 72, at a single intersection. State route IL 72 travels 
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3-85

1 east and north at that intersection. County Highway 33 travels west. German Church Road 

2 intersects State route IL 64 at a location 5 to 6 mi (8 to 9.5 km) south of the Byron entrance. 

3 Employees traveling from the north use a combination of State routes IL 2, IL 72, County 

4 Highway 33, and North German Church Road to reach the station. Employees traveling from 

5 the south use a combination of State routes IL 2, IL 64, and South German Church Road to 

6 reach the station.

7 Exelon Generation employees report that there has been no traffic congestion in the area during 

8 normal operations (Exelon 2013a). During major refueling or maintenance outages, both 

9 entrances are opened to alleviate potential traffic congestion. During the first weeks of an 

10 outage, some traffic backups occur at the northern entrance because the back shifts have not 

11 yet started and most outage workers are on the first shift. Once the back shifts start, traffic 

12 congestion usually abates. Byron maintenance crews add signage to warn drivers of temporary 

13 traffic congestion in the area. Byron employees do not recall any congestion issues during the 

14 1998 steam generator replacement project (Exelon 2013a).

15 Table 3-32 lists commuting routes to the Byron site and average annual daily traffic (AADT) 

16 volume values. The AADT values represent traffic volumes for a 24-hour period factored by 

17 both the day of the week and the month of the year.

18 Table 3–32. Major Commuting Routes in the Vicinity of Byron: 2012 AADT

Roadway and Location Average Annual Daily Traffic (AADT)(a)

The section of North German Church Road between 

the station entrance and IL 72 1,300 – 2,250

On County Highway 33, near its intersection with North 

German Church Road 2,800

On IL 72, just east of its intersection with North German 

Church Road 12,300

The section of South German Church Road between 

the station entrance and IL 64 750 – 1,350

On IL 64, just east of the intersection with South 

German Church Road

(b)4,200

On IL 64, just west of the intersection with South 

German Church Road

(b)4,900

(a) Unless otherwise indicated, all AADTs represent traffic volume during the average 24-hour day during 2012.

(b) AADTs in 2011

Source: IDOT 2014

19 3.11 Human Health

20 3.11.1 Radiological Exposure and Risk

21 As required by NRC regulation, 10 CFR 20.1101, Exelon has a radiation protection program 

22 designed to protect onsite personnel, including employees, contractor employees, visitors, and 

23 offsite members of the public from radiation and radioactive material generated at Byron.
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1 The radiation protection program is extensive and includes, but is not limited to the following:

2  Organization and Administration (i.e., a Radiation Protection Manager who is 

3 responsible for the program and having trained and qualified workers),

4  Implementing procedures,

5  ALARA Program to minimize dose to workers and members of the public,

6  Dosimetry Program (i.e., measure radiation dose of plant workers),

7  Radiological Controls (i.e., protective clothing, shielding, filters, respiratory 

8 equipment, and individual work permits with specific radiological 

9 requirements),

10  Radiation Area Entry and Exit Controls (i.e., locked or barricaded doors, 

11 interlocks, local and remote alarms, personnel contamination monitoring 

12 stations),

13  Posting of Radiation Hazards (i.e., signs and notices alerting plant personnel 

14 of potential hazards),

15  Record Keeping and Reporting (i.e., documentation of worker dose and 

16 radiation survey data),

17  Radiation Safety Training (i.e., classroom training and use of mockups to 

18 simulate complex work assignments),

19  Radioactive Effluent Monitoring Management (i.e., control and monitor 

20 radioactive liquid and gaseous effluents released into the environment),

21  Radioactive Environmental Monitoring (i.e., sampling and analysis of 

22 environmental media, such as air, water, vegetation, food crops, direct 

23 radiation, and milk to measure the levels of radioactive material in the 

24 environmental that may impact human health), and

25  Radiological Waste Management (i.e., control, monitor, process, and dispose 

26 of radioactive solid waste).

27 Regarding the radiation exposure to Byron personnel, the NRC staff reviewed the data 

28 contained in NUREG–0713, Occupational Radiation Exposure at Commercial Nuclear Power 

29 Reactors and Other Facilities 2011: Forty-Fourth Annual Report (NUREG–0713, Volume 33) 

30 (Lewis et al. 2013). This report, which was the most recent available at the time of this review, 

31 summarizes the occupational exposure data through 2011 that are maintained in the NRC’s 

32 Radiation Exposure Information and Reporting System database. Nuclear power plants are 

33 required by 10 CFR 20.2206 to report their occupational exposure data to the NRC annually.

34 NUREG–0713 calculates a 3-year average collective dose per reactor for all nuclear power 

35 reactors licensed by the NRC. The 3-year average collective dose is one of the metrics that the 

36 NRC uses in the Reactor Oversight Program to evaluate the applicant’s ALARA program. 

37 Collective dose is the sum of the individual doses received by workers at a facility licensed to 

38 use radioactive material over a 1-year time period. There are no NRC or EPA standards for 

39 collective dose. Based on the data for operating PWRs like those at Byron, the average annual 

40 collective dose per reactor was 59.71 person-rem. In comparison, Byron had a reported annual 

41 collective dose per reactor of 63.99 person-rem.

42 In addition, as reported in NUREG–0713, for 2011, no worker at Byron received an annual dose

43 greater than 2.0 rem (0.02 sievert (Sv)), which is well below the NRC occupational dose limit of 

44 5.0 rem (0.05 Sv) in 10 CFR 20.1201.
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1 3.11.2 Chemical Hazards

2 The use, storage, and discharge of chemicals, biocides, and sanitary wastes, as well as minor 

3 chemical spills are regulated by State and Federal environmental agencies. Chemical hazards 

4 to plant workers resulting from continued operations and refurbishment associated with license 

5 renewal are expected to be minimized by the applicant’s implementing good industrial hygiene 

6 practices as required by permits and Federal and State regulations. Plant discharges of these 

7 chemical and sanitary wastes are monitored and controlled as part of the plant’s NPDES permit 

8 process to minimize impacts to the public and the environment. In addition, proposed changes 

9 in the use of cooling water treatment chemicals would require review by the plant’s NPDES 

10 permit-issuing authority and possible modification of the existing NPDES permit, including 

11 examination of the human health effects of the change.

12 The use, storage, and discharge of chemicals and sanitary wastes at Byron are controlled in 

13 accordance with Exelon’s fleet chemical control procedures and site-specific chemical spill 

14 prevention plans. Exelon’s Spill Prevention, Control and Countermeasure plan serves as the 

15 site’s hazardous waste contingency plan. Chemical wastes are controlled and managed in 

16 accordance with Exelon’s waste management procedure. These plant procedures and plans 

17 are designed to prevent and minimize the potential for a chemical or hazardous waste release 

18 that could impact workers, members of the public, and the environment (Exelon 2003).

19 3.11.3 Microbiological Hazards

20 Radioactive Waste Nuclear plants that have cooling towers and that discharge thermal effluents 

21 to cooling ponds, lakes, canals, or rivers, such as Byron, have the potential to promote the 

22 increased growth of thermophilic microorganisms, which could result in adverse health effects 

23 for plant workers and the public. Microorganisms of particular concern include several types of 

24 bacteria (Legionella spp., Salmonella spp., Shigella spp., and Pseudomonas aeruginosa) and 

25 the free-living amoeba Naegleria fowleri. 

26 Nuclear plant workers can be exposed to Legionella spp. when performing maintenance 

27 activities on plant cooling systems if workers inhale cooling tower vapors, because vapors are 

28 often within the optimum temperature range for Legionella growth. Plant personnel most likely 

29 to come in contact with Legionella aerosols would be workers who clean biofilms off of 

30 condenser tubes, cooling towers, and related system components or equipment. Exposure of 

31 the public to Legionella from nuclear plant operations is generally not a concern, because 

32 Legionella exposure would be confined to a small area of the site within the protected area.

33 The public can be exposed to the thermophilic microorganisms Salmonella, Shigella, 

34 P. aeruginosa, and N. fowleri during swimming, boating, or other recreational uses of fresh 

35 water. If a nuclear plant’s thermal effluent enhances the growth of thermophilic microorganisms, 

36 recreational users could experience an elevated risk of exposure when using waters near the 

37 plant’s discharge. 

38 Thermophilic Microorganisms of Concern

39 Legionella is a genus of common warm water bacteria that occurs in lakes, ponds, and other 

40 surface waters, as well as some groundwater sources and soils. The bacteria are pathogenic to 

41 humans when aerosolized and inhaled into the lungs. Approximately 2 to 5 percent of those 

42 exposed in this way to Legionella develop an acute bacterial infection of the lower respiratory 

43 tract known as Legionnaires’ disease (Pearson 2003). Optimal growth occurs in stagnant 

44 surface waters with biofilms or slimes that range in temperature from 35 to 45 °C (95 to 113 °F), 

45 though the bacteria can persist in waters from 20 to 50 °C (68 to 122 °F) (Pearson 2003). 

46 Elderly and immunocompromised individuals are most susceptible to Legionnaires’ disease 
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1 (Pearson 2003). According to data from the Centers for Disease Control and Prevention 

2 (CDC 2011a) from 2000 through 2009, New England and Middle Atlantic states generally have 

3 the highest number of reported legionellosis cases each year.

4 Approximately 2,000 serotypes of Salmonella spp. cause the bacterial infection salmonellosis in 

5 humans. Of these, the serotypes Typhimurium and Enteritidis are the most common in the 

6 United States (CDC 2010a). Salmonellosis is most common in summer months, and it is 

7 transmitted through contact with food, water, or animals contaminated with human or animal 

8 feces (CDC 2010a). The bacteria have an optimal growth temperature of 98.6 °F (37°C) but 

9 can grow at temperatures ranging from 43 to 115°F (6 to 46°C) (Albrecht 2013a). Studies 

10 examining the persistence of Salmonella spp. outside of a host have found that Salmonella can 

11 survive for several months in water and in aquatic sediments (Moore et al. 2003).

12 Shigella is a genus of bacteria species that causes shigellosis (i.e., bacterial dysentery), which 

13 is spread through consuming fecal-contaminated food or water or by swimming in contaminated 

14 water. Its optimum growth temperature is 37 °C (98.6 °F), though it can grow in water 

15 temperatures ranging from 10 to 40 °C (50 to 104°F) (Albrecht 2013b). Shigellosis is most 

16 common in summer months and among toddlers age 2 to 4 in childcare settings (CDC 2013e).

17 Pseudomonas aeruginosa is a free-living bacterium found in soil, water, and plant surfaces. It is 

18 most commonly linked to infections transmitted in healthcare settings. However, as a 

19 waterborne pathogen, it can cause ear infections (i.e., “swimmer’s ear”), eye infections, and skin 

20 rashes after exposure to contaminated hot tubs, swimming pools, or other recreational waters 

21 (CDC 2013a). Its optimum growth temperature is 37°C (98.6°F), though it can grow at 

22 temperatures as high as 42 °C (107.6°F) (Todar 2004). P. aeruginosa almost exclusively infects 

23 immunocompromised individuals or already injured or inflamed sites on the skin (Todar 2004).

24 Naegleria fowleri is a free-living amoeba that occurs in warm lakes, rivers, or hot springs. It is 

25 the causative agent of human primary amoebic meningoencephalitis (PAM). Infection occurs 

26 when contaminated freshwater enters the nose, and the amoeba migrates to brain tissue; the 

27 ensuing illness is usually fatal (CDC 2013b). N. fowleri grows best at higher temperatures up to 

28 46°C (115°F) (CDC 2013b), though it has also been isolated from thermally altered waters 

29 surrounding power plant discharges at temperatures ranging from 35 to 41°C (95 to 105.8°F) 

30 (Stevens et al. 1977).

31 Prevalence of Waterborne Diseases Associated with Recreational Waters

32 From 2002 through 2011, the CDC (2003, 2004a, 2005, 2006a, 2007, 2008a, 2009, 2010b, 

33 2011b, 2012) reported an average of 2,774 cases of Legionnaires’ disease per year, of which 

34 between 28 and 151 per year were reported from Illinois. Although Legionella is often present 

35 in the cooling tower vapors of power plants, cases of Legionnaires’ disease from this type of 

36 exposure are rare due to workers’ use of appropriate respiratory protection.

37 The Illinois Department of Public Health (IDPH) indicates that approximately 1,500 to 

38 2,000 cases of salmonellosis are reported in the State each year (IDPH 2009). However, the 

39 overwhelming majority of salmonellosis cases are foodborne (CDC 2010a). The CDC reports 

40 biannually on waterborne disease outbreaks associated with recreational waters. A review of 

41 the past 10 available data years (1999 through 2008) of these reports indicates that no 

42 outbreaks or cases of waterborne Salmonella infection from recreational waters occurred in the 

43 United States during this timeframe (CDC 2002, 2004b, 2006b, 2008b, 2011c). From 2006 to 

44 2013, all CDC-reported salmonellosis outbreaks have been caused by contaminated produce, 

45 meats, or prepared foods or through contact with contaminated animals (CDC 2013d).

46 Approximately 1,300 confirmed cases of shigellosis are reported in Illinois each year 

47 (IDPH 2013). CDC reports (2002, 2004b, 2006b, 2008b, 2011c) indicate that less than a 
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1 dozen shigellosis outbreaks have been attributed to lakes, reservoirs, and other recreational 

2 waters in the past 10 available data years (1999 through 2008). None of these cases were in 

3 Illinois.

4 Infections attributed to Pseudomonas aeruginosa are most commonly contracted in pools, spas, 

5 and hot tubs. No cases of infection linked to contaminated recreational waters in the 

6 United States have been reported within the past 10 available data years (1999 through 2008) 

7 (CDC 2002, 2004b, 2006b, 2008b, 2011c).

8 The N. fowleri-caused disease, PAM, is rare in the United States. Since 1962, between zero 

9 and eight cases of PAM have been reported to the CDC annually, and no cases have been 

10 reported in Illinois (CDC 2013c)

11 3.11.4 Electromagnetic Fields

12 Based on the GEIS, the Commission found that electric shock resulting from direct access to 

13 energized conductors or from induced charges in metallic structures has not been found to be a 

14 problem at most operating plants and generally is not expected to be a problem during the 

15 license renewal term. However, a site-specific review is required to determine the significance 

16 of the electric shock potential along the portions of the transmission lines that are within the 

17 scope of this SEIS.

18 In the GEIS, the NRC found that without a review of the conformance of each nuclear plant 

19 transmission line with National Electrical Safety Code® (NESC®) criteria, it was not possible to 

20 determine the significance of the electric shock potential (IEEE 2002). Evaluation of individual 

21 plant transmission lines is necessary because the issue of electric shock safety was not 

22 addressed in the licensing process for some plants. For other plants, land use in the vicinity of 

23 transmission lines may have changed, or power distribution companies may have chosen to 

24 upgrade line voltage. To comply with 10 CFR 51.53(c)(3)(ii)(H), the applicant must provide an 

25 assessment of the impact of the proposed action on the potential shock hazard from the 

26 transmission lines if the transmission lines that were constructed for the specific purpose of 

27 connecting the plant to the transmission system do not meet the recommendations of the NESC 

28 for preventing electric shock from induced currents. The NRC uses the NESC criteria and the 

29 applicant’s adherence to those criteria during the current operating license as its baseline to 

30 assess the potential human health impact of the induced current from an applicant’s 

31 transmission lines. As discussed in the GEIS, the issue of electric shock is of small significance 

32 for transmission lines that are operated in adherence with the NESC criteria.

33 Byron’s associated transmission lines were designed and constructed in accordance with the 

34 Illinois Commerce Commission General Order 160 and the sixth edition of the NESC. ComEd is 

35 the owner and operator of the transmission lines and has surveillance and maintenance 

36 procedures to assure that current ground clearances will not change. ComEd performs routine 

37 inspections and aerial patrols to check for encroachments, broken conductors, or any other 

38 evidence of clearance issues.

39 Exelon used the Power Line Systems Software program (PLS-CADDTM) to analyze the 

40 three-dimensional models created from the LIDAR (Light Detection and Ranging) data and 

41 calculate the potential for induced shock effects. All electromagnetic field calculations in 

42 PLS-CADD are based on the Electric Power Research Institute methodology. Of the 

43 three 345-kV transmission lines studied, Exelon reported that none exceed the 5-milliampere 

44 NESC standard (Exelon 2013a).
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1 3.11.5 Other Hazards

2 Two additional human health issues are addressed in this section: physical occupational 

3 hazards and electric shock hazards.

4 Nuclear power plants are industrial facilities that have many of the typical occupational hazards 

5 found at any other electric power generation utility. Workers at or around nuclear power plants 

6 would be involved in some electrical work, electric power line maintenance, repair work, and 

7 maintenance activities and exposed to some potentially hazardous physical conditions 

8 (e.g., falls, excessive heat, cold, noise, electric shock, and pressure). The issue of physical 

9 occupational hazards is generic to all nuclear power plants.

10 The Occupational Safety & Health Administration (OSHA) is responsible for developing and 

11 enforcing workplace safety regulations. OSHA was created by the Occupational Safety and 

12 Health Act of 1970 (OSH Act) (29 U.S.C. 651 et seq.), which was enacted to safeguard the 

13 health of workers. With specific regard to nuclear power plants, plant conditions that result in an 

14 occupational risk, but do not affect the safety of licensed radioactive materials, are under the 

15 statutory authority of OSHA rather than the NRC as set forth in a Memorandum of 

16 Understanding (53 FR 42950, October 31, 1988) between the NRC and OSHA. Occupational 

17 hazards can be minimized when workers adhere to safety standards and use appropriate 

18 protective equipment; however, fatalities and injuries from accidents can still occur.

19 Byron maintains an occupational safety program in accordance with OSHA regulations for its 

20 workers (Exelon 2013a).

21 3.12 Environmental Justice

22 Environmental Justice Under Executive Order (EO) 12898 (59 FR 7629), Federal agencies are 

23 responsible for identifying and addressing, as appropriate, disproportionately high and adverse 

24 human health and environmental impacts on minority and low-income populations. In 2004, the 

25 Commission issued a Policy Statement on the Treatment of Environmental Justice Matters in 

26 NRC Regulatory and Licensing Actions (69 FR 52040), which states, “The Commission is 

27 committed to the general goals set forth in EO 12898, and strives to meet those goals as part of 

28 its National Environmental Policy Act (NEPA) review process.”

29 The Council on Environmental Quality (CEQ) provides the following information in 

30 Environmental Justice: Guidance Under the National Environmental Policy Act (CEQ 1997):

31 Disproportionately High and Adverse Human Health Effects.

32 Adverse health effects are measured in risks and rates that could result in latent 

33 cancer fatalities, as well as other fatal or nonfatal adverse impacts on human 

34 health. Adverse health effects may include bodily impairment, infirmity, illness, or 

35 death. Disproportionately high and adverse human health effects occur when the 

36 risk or rate of exposure to an environmental hazard for a minority or low-income 

37 population is significant (as employed by NEPA) and appreciably exceeds the 

38 risk or exposure rate for the general population or for another appropriate 

39 comparison group.

40 Disproportionately High and Adverse Environmental Effects.

41 A disproportionately high environmental impact that is significant (as employed 

42 by NEPA) refers to an impact or risk of an impact on the natural or physical 

43 environment in a low-income or minority community that appreciably exceeds the 

44 environmental impact on the larger community. Such effects may include 

45 ecological, cultural, human health, economic, or social impacts. An adverse 

46 environmental impact is an impact that is determined to be both harmful and 
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1 significant (as employed by NEPA). In assessing cultural and aesthetic

2 environmental impacts, impacts that uniquely affect geographically dislocated or

3 dispersed minority or low-income populations or American Indian tribes are 

4 considered.

5 The environmental justice analysis assesses the potential for disproportionately high and 

6 adverse human health or environmental effects on minority and low-income populations that 

7 could result from the operation of Byron during the renewal term. In assessing the impacts, the 

8 following definitions of minority individuals and populations and low-income population were 

9 used (CEQ 1997):

10 Minority individuals

11 Individuals who identify themselves as members of the following population 

12 groups: Hispanic or Latino, American Indian or Alaska Native, Asian, Black or 

13 African American, Native Hawaiian or Other Pacific Islander, or two or more 

14 races, meaning individuals who identified themselves on a Census form as being 

15 a member of two or more races, for example, White and Asian.

16 Minority populations

17 Minority populations are identified when (1) the minority population of an affected 

18 area exceeds 50 percent or (2) the minority population percentage of the affected 

19 area is meaningfully greater than the minority population percentage in the 

20 general population or other appropriate unit of geographic analysis.

21 Low-income population

22 Low-income populations in an affected area are identified with the annual 

23 statistical poverty thresholds from the Census Bureau’s Current Population 

24 Reports, Series P60, on Income and Poverty.

25 3.12.1 Minority Population

26 According to 2010 Census data, approximately 20 percent of the population residing within a 

27 50-mi (80-km) radius of Byron identified themselves as minority individuals. The largest minority 

28 group was Hispanic or Latino (of any race) (11 percent), followed by Black or African-American 

29 (5 percent) (USCB 2014a).

30 According to 2010 Census data, minority populations in the socioeconomic ROI (Lee, Ogle, and 

31 Winnebago counties) composed 23.7 percent of the total two-county population (see 

32 Table 3–19). Figure 3–13 shows predominantly minority population block groups, using 2010 

33 Census data for race and ethnicity, within a 50-mi (80-km) radius of Byron.

34 Census block groups were considered minority population block groups if the percentage of the 

35 minority population within any block group exceeded 20 percent (the percent of the minority 

36 population within the 50-mi (80–km) radius of Byron). A minority population exists if the 

37 percentage of the minority population within the block group is meaningfully greater than the 

38 minority population percentage in the 50-mi (80-km) radius. Approximately 356 of the 

39 979 census block groups located within the 50-mi (80-km) radius of Byron have meaningfully 

40 greater minority populations (USCB 2014f).

41 As shown in Figure 3–13, the nearest minority population block groups (race and ethnicity) are 

42 mostly clustered near Rockford, Rochelle, and Freeport, Illinois. None of the block groups near 

43 Byron have meaningfully greater minority populations.
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1 Figure 3–13. Minority Block Groups Within a 50-mi Radius of Byron

2 

3 Source: USCB 2014f

N 

° Cities • Aggregate Minority Population * Byron Nuclear Generating Station D County Boundaries -~ usa Mile Buffer L __ : State Boundaries 

W+ E 

s 

0 3 6 12 18 24 

-=::.:=---====---Miles 
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1 3.12.2 Low-Income Population

2 According to the USCB’s 2008–2012 American Community Survey 5 Year Estimates, an 

3 average of 7.7 percent of families and 11.8 percent of individuals residing within a 50-mi 

4 (80-km) radius of Byron were identified as living below the Federal poverty threshold 

5 (USCB 2014a). The 2012 Federal poverty threshold was $23,942 for a family of four.

6 According to the USCB’s 2008–2012 American Community Survey 5 Year Estimates, 

7 10 percent of families and 13.7 percent of individuals in Illinois were living below the Federal 

8 poverty threshold in 2012, and the median household income for Illinois was $56,853 

9 (USCB 2014a). People living in the socioeconomic ROI (Lee, Ogle, and Winnebago Counties) 

10 had median household incomes below the State average. Winnebago County had the lowest 

11 median household income average ($47,573) of the three counties and the highest percentages 

12 of persons (17 percent of individuals and 12.8 percent of families) living below the poverty level. 

13 Lee and Ogle Counties had median household income averages of $50,342 and $55,590, 

14 respectively, and each had 10 percent of individuals and 7.4 percent of families, respectively, 

15 living below the poverty level (USCB 2014a).

16 Figure 3–14 shows the location of predominantly low-income population block groups within a 

17 50-mi (80-km) radius of Byron. Census block groups were considered low-income population 

18 block groups if the percentage of individuals living below the Federal poverty threshold within 

19 any block group exceeded 11.8 percent (the percent of the individuals living below the Federal 

20 poverty threshold within the 50-mi (80-km) radius of Byron). Approximately 337 of the 

21 979 census block groups located within the 50-mi (80-km) radius of Byron have meaningfully 

22 greater low-income populations (USCB 2014f).

23 As shown in Figure 3–14, the nearest low-income population block groups are mostly clustered 

24 near Rockford, Rochelle, and Freeport, Illinois. None of the block groups encompassing Byron 

25 have meaningfully greater low-income populations.
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1 Figure 3–14. Low-Income Block Groups Within a 50-mi (80-km) Radius of Byron

2 

3 Source: USCB 2014f

N 

° Cities • Low Income Population * Byron Nuclear Generating Station D County Boundaries 

U50 Mile Buffer __j State Boundaries 

W+ E 

s 

0 3 6 12 18 24 

-==-:=---===:::::i-....1 Miles 
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1 3.13 Waste Management and Pollution Prevention

2 3.13.1 Radioactive Waste

3 As discussed in Section 3.1.4 of this SEIS, Byron uses liquid, gaseous, and solid waste

4 processing systems to collect and treat, as needed, radioactive materials produced as a 

5 byproduct of plant operations. Radioactive materials in liquid and gaseous effluents are 

6 reduced prior to being released into the environment so that the resultant dose to members of 

7 the public from these effluents is well within NRC and EPA dose standards. Radionuclides that 

8 can be efficiently removed from the liquid and gaseous effluents prior to release are converted 

9 to a solid waste form for disposal in a licensed disposal facility.

10 3.13.2 Nonradioactive Waste

11 Waste minimization and pollution prevention are important elements of operations at all nuclear 

12 power plants. The applicants are required to consider pollution prevention measures as 

13 dictated by the Pollution Prevention Act of 1990 (PPA) (Public Law (PL) 101-508) and Resource 

14 Conservation and Recovery Act (RCRA) (PL 94-580).

15 As described in Section 3.1.5, Byron has a nonradioactive waste management program to 

16 handle this nonradioactive waste. In addition to managing its nonradioactive waste, Exelon has 

17 programs in place to minimize the generation of this waste. Byron implements a hazardous 

18 waste minimization plan to reduce, to the extent feasible, waste generated, treated, 

19 accumulated, or disposed (Exelon 2003). This plan documents waste streams that have been 

20 eliminated and lists current waste streams generated at the facility (Exelon 2003). The plan is 

21 updated annually and used in conjunction with plant waste management procedures on solid, 

22 special, hazardous, mixed waste, and chemicals to control and minimize waste generation to 

23 the maximum extent practicable.

24 3.14 References

25 10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, “Standards for 

26 protection against radiation.”

27 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic licensing of 

28 production and utilization facilities.”

29 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

30 protection regulations for domestic licensing and related regulatory functions.”

31 10 CFR Part 61. Code of Federal Regulations, Title 10, Energy, Part 61, “Licensing 

32 requirements for land disposal of radioactive waste.”

33 10 CFR Part 71. Code of Federal Regulations, Title 10, Energy, Part 71, “Packaging and 

34 transportation of radioactive material.”

35 10 CFR Part 72. Code of Federal Regulations, Title 10, Energy, Part 72, “Licensing 

36 requirements for the independent storage of spent nuclear fuel, high-level radioactive waste, 

37 and reactor-related Greater than Class C waste.”

38 40 CFR Part 50. Code of Federal Regulations, Title 40, Protection of Environment, Part 50, 

39 “National primary and secondary ambient air quality standards.”

40 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of Environment, Part 51, 

41 “Requirements for preparation, adoption, and submittal of implementation plans.”
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1 40 CFR Part 81. Code of Federal Regulations, Title 40, Protection of Environment, Part 81, 

2 “Designation of areas for air quality planning purposes.”

3 40 CFR Part 190. Code of Federal Regulations, Title 40, Protection of Environment, Part 190, 

4 “Environmental radiation protection standards for nuclear power operations.”

5 49 CFR Parts 171–178. Code of Federal Regulations, Title 49, Transportation, Subchapter C—

6 Hazardous Materials Regulations and “Specifications for packagings.”

7 50 CFR Part 10. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 10, “General 

8 provisions,” Section 10.12, “Definitions.”

9 50 CFR Part 22. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 22, “Eagle 

10 permits,” Section 22.3, “Definitions.”

11 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 

12 “Interagency cooperation—Endangered Species Act of 1973, as amended.”

13 32 FR 4001. U.S. Fish and Wildlife Service. “Endangered species.” Federal 

14 Register 32(48):4001. March 11, 1967.

15 41 FR 41914. U.S. Fish and Wildlife Service. “Endangered and threatened wildlife and plants; 

16 determination of critical habitat for American crocodile, California condor, Indiana bat, and 

17 Florida manatee.” Federal Register 41(187):41914–41916. September 24, 1976.

18 52 FR 781. U.S. Fish and Wildlife Service. “Endangered and threatened wildlife and plants; 

19 determination of threatened status for Lespedeza leptostachya (prairie bush-clover).” Federal 

20 Register 52(6):781–785. January 9, 1987. Available at 

21 <http://ecos.fws.gov/docs/federal_register/fr1213.pdf> (accessed 29 October 2013).

22 54 FR 39857. U.S. Fish and Wildlife Service. “Endangered and threatened wildlife and plants; 

23 determination of threatened status for eastern and western prairie fringed orchids.” Federal 

24 Register 54(187):39857–39863. September 28, 1989. Available at 

25 <http://ecos.fws.gov/docs/federal_register/fr1602.pdf> (accessed 30 October 2013).

26 56 FR 19953. U.S. Fish and Wildlife Service. “Endangered and threatened wildlife and plants; 

27 Dalea foliosa (leafy prairie-clover) determined to be endangered.” Federal Register 

28 56(84):19953–19959. May 1, 1991. Available at 

29 <http://ecos.fws.gov/docs/federal_register/fr1847.pdf> (accessed 7 January 2014).

30 59 FR 7629. Executive Order No. 12898. “Federal actions to address environmental justice in 

31 minority populations and low-income populations.” Federal Register 59(32):7629–7634. 

32 February 16, 1994.

33 69 FR 41576. U.S. Environmental Protection Agency. “National Pollutant Discharge Elimination 

34 System—final regulations to establish requirements for cooling water intake structures at 

35 Phase II existing facilities.” Federal Register 69(131):41576–41693. July 9, 2004.

36 69 FR 52040. U.S. Nuclear Regulatory Commission. “Policy statement on the treatment of 

37 environmental justice matters in NRC regulatory and licensing actions.” Federal Register 

38 69(163):52040–52048. August 24, 2004.

39 74 FR 56260. U.S. Environmental Protection Agency. “Mandatory reporting of greenhouse

40 gases.” Federal Register 74(209):56260–56519. October 30, 2009.

41 75 FR 31514. U.S. Environmental Protection Agency. “Prevention of Significant Deterioration 

42 and Title V Greenhouse Gas Tailoring Rule.” Federal Register 75(106)31514–31608. 

43 June 3, 2010.
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4 78 FR 61046. U.S. Fish and Wildlife Service. “Endangered and threatened wildlife and plants; 

5 12-month finding on a petition to list the eastern small-footed bat and the northern long-eared 

6 bat as endangered or threatened species; listing the northern long-eared bat as an endangered 

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8 <http://www.gpo.gov/fdsys/pkg/FR-2013-10-02/pdf/2013-23753.pdf> (accessed 

9 30 January 2014).

10 78 FR 72058. U.S. Fish and Wildlife Service. “Endangered and threatened wildlife and plants; 

11 listing the northern long-eared bat as an endangered species.” Federal 

12 Register 78(231):72058–72059. December 2, 2013. Available at 

13 <http://www.gpo.gov/fdsys/pkg/FR-2013-12-02/pdf/2013-28705.pdf> (accessed 

14 30 January 2014).

15 35 IAC 302. Illinois Administrative Code, Title 35, Environmental Protection, Subtitle C, “Water 

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44 Albrecht JA. 2013b. “University of Nebraska-Lincoln Food: Bacteria Causing Foodborne Illness: 

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Affected Environment

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3 M.P. Gallagher, Vice President – License Renewal Projects, Exelon, to NRC. Subject: 

4 Response to NRC Request for Additional Information - Additional Request, dated 

5 January 29, 2014, related to the Byron and Braidwood Stations, Units 1 and 2 License Renewal 

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12 Projects, Exelon, to NRC. Subject: Response to NRC request for additional information dated 

13 November 21, 2013, related to the Byron and Braidwood Stations, Units 1 and 2, license 

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25 2, Response to NRC Request for Additional Information, dated November 21, 2013, Related to 

26 the Byron and Braidwood Stations, Units 1 and 2 License Renewal Application, Byron Station 

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28 (Part 2 of 15).

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30 Byron Nuclear Power Station. June 2003. Available in: Letter from M.P. Gallagher, 

31 Vice President – License Renewal Projects, to NRC. Subject: Response to NRC request for 

32 additional information dated November 21, 2013, related to the Byron and Braidwood Stations, 

33 Units 1 and 2, license renewal application, Byron Station applicant’s Environmental Report.

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36 Station Report Submitted to the Illinois State Water Survey for Calendar Year 2008). Available 

37 in: “Byron, Units 1 and 2, response to NRC request for additional information, dated 

38 November 21, 2013, related to the Byron and Braidwood Stations, Units 1 and 2, license 

39 renewal application, Byron Station applicant’s Environmental Report.” December 19, 2013. 

40 ADAMS No. ML14007A088 (Part 13 of 15).

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42 April 24, 2009. Available in: “Byron, Units 1 and 2, Response to NRC request for additional 

43 information, dated November 21, 2013, related to the Byron and Braidwood Stations, Units 1 

44 and 2, license renewal application, Byron Station applicant’s Environmental Report.” 

45 December 19, 2013. ADAMS No. ML14007A088 (Part 13 of 15).
Affected Environment

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3 94 p. ADAMS No. ML091200667.

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6 in: “Byron, Units 1 and 2, response to NRC request for additional information, dated 

7 November 21, 2013, related to the Byron and Braidwood Stations, Units 1 and 2, license 

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9 ADAMS No. ML14007A088 (Part 13 of 15). 

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14 December 19, 2013. ADAMS No. ML14007A088 (Part 13 of 15).

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16 Radiological Effluent Release Report (ARERR), 2009. Byron, IL. 50 p. ADAMS 

17 No. ML101230140.

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19 Station Report Submitted to the Illinois State Water Survey for Calendar Year 2010). Available 

20 in: “Byron, Units 1 and 2, response to NRC request for additional information, dated 

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23 ADAMS No. ML14007A088 (Part 13 of 15). 

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25 April 14, 2011. Available in: “Byron, Units 1 and 2, response to NRC request for additional 

26 information, dated November 21, 2013, related to the Byron and Braidwood Stations, Units 1 

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28 December 19, 2013. ADAMS No. ML14007A088 (Part 13 of 15).

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30 Radiological Effluent Release Report (ARERR), 2010. Byron, IL: Exelon Nuclear. April 29, 2011. 

31 78 p. ADAMS No. ML111730662.

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33 Station Report Submitted to the Illinois State Water Survey for Calendar Year 2011). Available 

34 in: “Byron, Units 1 and 2, response to NRC request for additional information, dated

35 November 21, 2013, related to the Byron and Braidwood Stations, Units 1 and 2, license 

36 renewal application, Byron Station applicant’s Environmental Report.” December 19, 2013. 

37 ADAMS No. ML14007A088 (Part 13 of 15).

38 [Exelon] Exelon Generation Company, LLC. 2011d, Request for License Amendment Regarding 

39 Measurement Uncertainty Recapture (MUR) Power Uprate. June 23, 2011. ADAMS 

40 No. ML111790026 (package).

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42 April 26, 2012. Available in: “Byron, Units 1 and 2, response to NRC request for additional 

43 information, dated November 21, 2013, related to the Byron and Braidwood Stations, Units 1 

44 and 2, license renewal application, Byron Station applicant’s Environmental Report.” 

45 December 19, 2013. ADAMS No. ML14007A088 (Part 13 of 15).
Affected Environment

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6 ADAMS No. ML122290703.

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8 Updated Final Safety Analysis Report (UFSAR). Revision 14. December 14, 2012. ADAMS 

9 No. ML130040043.

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11 Station Report Submitted to the Illinois State Water Survey for Calendar Year 2012). Available 

12 in: “Byron, Units 1 and 2, response to NRC request for additional information, dated 

13 November 21, 2013, related to the Byron and Braidwood Stations, Units 1 and 2, license 

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15 ADAMS No. ML14007A088 (Part 13 of 15).

16 [Exelon] Exelon Generation Company, LLC. 2013a. Applicant’s Environmental Report – 

17 Operation License Renewal Stage Byron Station – Unit 1, License No. NPF-37, Unit 2, License 

18 No. NPF-66. May 2013. ADAMS No. ML131550528 (package).

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20 – License Renewal Projects, Exelon, to NRC. Subject: Byron, Units 1 and 2, response to NRC 

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22 Braidwood, Units 1 and 2, license renewal application, Byron Station applicant’s Environmental 

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25 February 13, 2013. Available in: “Byron, Units 1 and 2, response to NRC request for additional 

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35 November 21, 2013, Related to the Byron and Braidwood Stations, Units 1 and 2 License 

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37 No. ML14007A089.

38 [Exelon] Exelon Generation Company, LLC. 2013g. Byron Nuclear Station Annual Radiological 

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26 [USDA] U.S. Department of Agriculture. 2013. “Web Soil Survey.” Custom Soil Resource Report 

27 for Ogle County, Illinois. Available at 

28 <http://websoilsurvey.nrcs.usda.gov/app/WebSoilSurvey.aspx> (accessed 19 June 2013).

29 [USFS] U.S. Forest Service. 1996. Ecological Subregions of the United States. Chapter 28, 

30 Prairie parkland (temperate). Available at 

31 <http://www.fs.fed.us/land/pubs/ecoregions/ch28.html#251G> (accessed 7 February 2014).

32 [USGS] U.S. Geological Survey. 2009. Earthquake Hazard in the New Madrid Seismic Zone 

33 Remains a Concern. Denver, CO: USGS. Fact Sheet 2009-3071. August 2009. 2 p. Available at 

34 <http://pubs.usgs.gov/fs/2009/3071/pdf/FS09-3071.pdf> (accessed 5 September 2013).

35 [USGS] U.S. Geological Survey. 2013a. “Earthquake History of Illinois.” Available at 

36 <http://earthquake.usgs.gov/earthquakes/states/illinois/history.php> (accessed 

37 4 September 2013).

38 [USGS] U.S. Geological Survey. 2013b. “Historic Earthquakes: Largest Earthquake in Illinois.” 

39 November 1, 2012. Available at 

40 <http://earthquake.usgs.gov/earthquakes/states/events/1968_11_09.php> (accessed 

41 4 September 2013).

42 [USGS] U.S. Geological Survey. 2013c. “Historic Earthquakes: Isoseismal Map of 1968 

43 earthquake.” Available at 

44 <http://earthquake.usgs.gov/earthquakes/states/events/1968_11_09_iso.php> (accessed 

45 4 September 2013).
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1 [USGS] U.S. Geological Survey. 2013d. Water-Resources Data for the United States, Water 

2 Year 2012. Water-Data Report WDR-US-2012, site 05440700. 7 p. Available at 

3 <http://wdr.water.usgs.gov/wy2012/pdfs/05440700.2012.pdf> (accessed 2 February 2014).

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5 Year 2012. Water-Data Report WDR-US-2012, site 05443500. 5 p. Available at 

6 <http://wdr.water.usgs.gov/wy2012/pdfs/05443500.2012.pdf> (accessed 2 February 2014).

7 Visocky AP, Sherrill MG, Cartwright K. 1985. Geology, Hydrology, and Water Quality of the 

8 Cambrian and Ordovician Systems in Northern Illinois. Champaign, IL: Illinois State Geological 

9 Survey and Illinois State Water Survey. Cooperative Groundwater Report 10. 144 p. Available at 

10 <http://isws.illinois.edu/pubdoc/COOP/ISWSCOOP-10.pdf> (accessed 16 December 2013).

11 Watrous KS, Donovan TM, Mickey RM, Darling SR, Hicks AC, Von Oettingen SL. 2006. 

12 Predicting minimum habitat characteristics for the Indiana bat in the Champlain Valley. The 

13 Journal of Wildlife Management 70(5):1228-1237. Available at 

14 <http://www.uvm.edu/rsenr/vtcfwru/Donovan/

15 Watrous%20et%20al.%202006%20Publication.pdf>.

16 Wetzel MJ, Ceas PA, Carney DA, Page LM. 1988. Survey of Rock River Fishes in the Vicinity of 

17 Castle Rock State Park, Ogle County, Illinois: Illinois Route 2-FAP 742 and Ridge Road–Pines 

18 Road Alternate. Champaign, IL: Illinois Natural History Survey. Section of Faunistic Surveys and 

19 Insect Identification Technical Report 1988 (4). April 15, 1988. 26 p. Available at 

20 <https://ideals.illinois.edu/handle/2142/10535> (accessed 18 October 2013).

21 [WHC] Wildlife Habitat Council. 2014. “Wildlife at Work—Wildlife Habitat Council promotes and 

22 certifies habitat conservation and management on working lands.” Available at 

23 <http://www.wildlifehc.org/programs/wildlife-at-work/> (accessed 7 February 2014).

24 Whitaker JO Jr, Brack V Jr. Distribution and summer ecology in Indiana. p 48–54. In: Kurta A, 

25 Kennedy J, editors. 2002. The Indiana Bat: Biology and Management of an Endangered 

26 Species. Austin, TX: Bat Conservation International. 253 p. Available at 

27 <http://www.environmentalsi.com/DOCS/PDFs/045.pdf>.

28 Wiken E, Jiménez Nava F, Griffith G. 2011. North American Terrestrial Ecoregions—Level III. 

29 Montréal, Canada: Commission for Environmental Cooperation. May 2011. 149 p. Available at 

30 <ftp://ftp.epa.gov/wed/ecoregions/pubs/

31 NA_TerrestrialEcoregionsLevel3_Final-2june11_CEC.pdf> (accessed 7 February 2011).

4-1 

1 4.0 ENVIRONMENTAL CONSEQUENCES AND MITIGATING ACTIONS

2 4.1 Introduction

3 In this chapter, the U.S. Nuclear Regulatory Commission (NRC) evaluates the environmental 

4 consequences of the proposed action (i.e., license renewal of Byron Station, Units 1 and 2 

5 (Byron)), including the (1) impacts associated with continued operations similar to those that 

6 have occurred during the current license terms; (2) impacts of various alternatives to the 

7 proposed action; (3) impacts from the termination of nuclear power plant operations and 

8 decommissioning after the license renewal term (with emphasis on the incremental effect 

9 caused by an additional 20 years of operation); (4) impacts associated with the uranium fuel 

10 cycle; (5) impacts of postulated accidents (design-basis accidents (DBAs) and severe 

11 accidents); (6) cumulative impacts of the proposed action; and (7) resource commitments

12 associated with the proposed action, including unavoidable adverse impacts, the relationship 

13 between short-term use and long-term productivity, and irreversible and irretrievable 

14 commitment of resources. The NRC also considers new and potentially significant information 

15 on environmental issues related to the impacts of operation during the renewal term.

16 NUREG-1437, Generic Environmental Impact Statement (GEIS) for License Renewal of Nuclear 

17 Plants (NRC 1996, 1999, 2013a) identifies 78 issues to be evaluated in the license renewal 

18 environmental review process. This supplemental environmental impact statement (SEIS) 

19 supplements the information provided in the GEIS. Generic issues (Category 1) rely on the 

20 analysis presented in the GEIS, unless otherwise noted. Applicable site-specific issues 

21 (Category 2) have been analyzed for Byron and assigned a significance level of SMALL, 

22 MODERATE, or LARGE. Section 1.4 of this SEIS provides an explanation of the criteria for 

23 Category 1 and Category 2 issues, as well as the definitions of SMALL, MODERATE, and 

24 LARGE. Resource-specific impact significance level definitions are provided where applicable.

25 4.2 Land Use and Visual Resources

26 This section describes the potential impacts of the proposed action (license renewal) and 

27 alternatives to the proposed action on land use and visual resources.

28 4.2.1 Proposed Action

29 Section 3.2 of this SEIS describes land use and visual resources in the vicinity of the Byron site. 

30 The four generic (Category 1) issues that apply to land use and visual resources during the 

31 proposed license renewal period appear in Table 4–1. The GEIS (NRC 2013a) discusses these 

32 issues in Section 4.2.1. The GEIS does not identify any site-specific (Category 2) land use or 

33 visual resource issues.

34 The NRC staff did not identify any new and significant information related to the generic 

35 (Category 1) issues listed above during the review of the applicant’s Environmental Report (ER) 

36 (Exelon 2013a), the site audit, or the scoping process. Therefore, the NRC expects no impacts 

37 associated with these issues beyond those discussed in the GEIS. The GEIS concludes that 

38 the impact level for each of these issues is SMALL.
Environmental Consequences and Mitigating Actions

4-2 

1 Table 4–1. Land Use and Visual Resources Issues

Issue GEIS Section Category

Land Use

Onsite land use 4.2.1.1 1

Offsite land use 4.2.1.1 1

Offsite land use in transmission line right-of-ways (ROWs)(a) 4.2.1.2 1

Visual Resources

Aesthetic impacts 4.2.1.2 1

(a)This issue applies only to the inscope portion of electric power transmission lines, which are defined as 

transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional 

power distribution system and transmission lines that supply power to the nuclear plant from the grid.

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51; NRC 2013a

2 4.2.2 No-Action Alternative

3 4.2.2.1 Land Use

4 If Byron were to shut down, the impacts to land use would remain similar to those during 

5 operations until the plant is fully decommissioned. Temporary buildings and staging or laydown 

6 areas may be required during large component and structure dismantling. Byron is likely to 

7 have sufficient space within previously disturbed areas for these needs, and therefore, no 

8 additional land would need to be disturbed that would result in changes to current land uses. In 

9 NUREG–0586, Generic Environmental Impact Statement on Decommissioning of Nuclear 

10 Facilities, Supplement 1, NRC (2002) concludes generically that land use impact during 

11 decommissioning activities would be SMALL. The GEIS (NRC 2013a) notes that land use 

12 impacts could occur in other areas beyond the immediate nuclear plant site as a result of the 

13 no-action alternative if new power plants are needed to replace lost capacity. The NRC staff did 

14 not identify any impacts that may result at Byron beyond those discussed in NUREG–0586. 

15 Thus, the NRC staff concludes that the impacts of the no-action alternative on land use during 

16 the proposed license renewal term would be SMALL.

17 4.2.2.2 Visual Resources

18 If Byron were to shut down, visual resources impacts would remain similar to those experienced 

19 during operations until the site is fully decommissioned. The cooling towers, which create the 

20 largest visual impact, may eventually be dismantled, which would reduce the already SMALL 

21 impacts to visual resources that would occur during the proposed license renewal term. Thus, 

22 the NRC staff concludes that the impacts of the no-action alternative on visual resources would 

23 be SMALL.

24 4.2.3 New Nuclear Alternative

25 4.2.3.1 Land Use

26 The new nuclear alternative assumes that the new facility would be built at an existing nuclear 

27 or retired coal plant site within the region of influence (ROI) but outside of Illinois. Construction 

28 of the new nuclear plant would require an estimated 324 acres (ac) (131 hectares (ha)) for 

29 permanent buildings and facilities and an additional 31 ac (12.5 ha) for temporary facilities and 
Environmental Consequences and Mitigating Actions

4-3 

1 laydown areas. The NRC staff assumes that this alternative would use existing onsite 

2 structures and previously disturbed areas to the extent practicable to minimize development of 

3 undisturbed land. Thus, this alternative would not significantly affect existing land uses. Given 

4 the land requirements, it is expected that some undisturbed lands would be affected, which 

5 would result in the conversion of natural areas to industrial areas. No additional land use 

6 changes would result from operation of the nuclear facility. The NRC staff concludes that the 

7 impacts to land use from construction and operation of a new nuclear alternative would be 

8 SMALL. 

9 4.2.3.2 Visual Resources

10 Because the facility would be located on an existing site, visual resources impacts of most new 

11 buildings and infrastructure would be minimal. The construction of natural draft cooling towers 

12 would be the largest visual impact because both the towers themselves and the plume could be 

13 visible from a distance. The magnitude of this impact would vary based on the topography of 

14 the chosen site and surrounding area. The NRC staff concludes that the impacts to visual 

15 resources from construction and operation of a new nuclear alternative would be SMALL to 

16 MODERATE.

17 4.2.4 Integrated Gasification Combined Cycle (IGCC) Alternative

18 4.2.4.1 Land Use

19 The IGCC alternative assumes that the new facility would be built at an existing 

20 energy-producing site or a retired coal plant site in Illinois or another state within the ROI. The 

21 facility would require 2,000 ac (809 ha) of land to construct the facility. The NRC staff assumes 

22 that this alternative would use existing onsite structures and previously disturbed areas to the 

23 extent practicable to minimize new development in undisturbed areas. However, because the 

24 footprint of the facility would be large, it is likely that construction would require clearing of lands 

25 that are currently in a different land use, such as agricultural, forested, or other natural areas. 

26 The impacts of this would vary widely based on the specific site selection and land uses that 

27 would be lost due to construction. No additional land use changes would result from operation 

28 of the IGCC facility. The NRC staff concludes that the impacts to land use from construction 

29 and operations of an IGCC alternative would be SMALL to MODERATE, primarily due to the 

30 potential for conversion of land to industrial use during construction.

31 4.2.4.2 Visual Resources

32 Because the facility would be located on an existing site, visual resources impacts would be 

33 minimal. The mechanical draft cooling towers would likely not be significantly taller than other 

34 buildings on the site. However, the plume created from operation of the towers could create 

35 noticeable visual impacts depending on the topography of the chosen site and surrounding 

36 area. The NRC staff concludes that the impacts to visual resources from construction and 

37 operation of an IGCC alternative would be SMALL to MODERATE.

38 4.2.5 Natural Gas Combined-Cycle (NGCC) Alternative

39 4.2.5.1 Land Use

40 The NGCC alternative assumes that the facility would be built at an existing energy-producing 

41 site or a retired coal plant site in Illinois or another state within the ROI. The facility would 

42 require 94 ac (38 ha) of land for the plant and associated pipelines. Because the footprint of the 

43 facility would be relatively small, the entire construction footprint could likely be sited in 

44 already-developed areas of the site, which would minimize land use changes. No additional 
Environmental Consequences and Mitigating Actions

4-4 

1 land use changes would result from operation of the NGCC facility. The NRC staff concludes 

2 that the impacts to land use from construction and operation of an NGCC alternative would be 

3 SMALL.

4 4.2.5.2 Visual Resources

5 Because the facility would be located on an existing site, visual resources impacts would be

6 minimal. The mechanical draft cooling towers would likely not be significantly taller than other 

7 buildings on the site. However, the plume created from operation of the towers could create 

8 noticeable visual impacts depending on the topography of the chosen site and surrounding 

9 area. The NRC staff concludes that the impacts to land use and visual resources from 

10 construction and operation of an NGCC alternative would be SMALL to MODERATE.

11 4.2.6 Combination Alternative (NGCC, Wind, Solar)

12 4.2.6.1 Land Use

13 The NGCC component of this alternative would require the same amount of land as the NGCC 

14 alternative (94 ac (38 ha)), but the NGCC component would likely make better use of existing 

15 infrastructure because it would be sited at an existing power plant in Illinois or another state 

16 within the ROI and could use buildings and structures that are already in place and operational 

17 for the existing facility. Land use impacts would be similar to or less than those described in 

18 Section 4.2.5 for the NGCC alternative and would, therefore, be SMALL.

19 The wind component of the combination alternative would require 3,376 ac (1,366 ha) to 

20 10,127 ac (4,098 ha) at sites across the ROI. However, the majority of this land would only be 

21 temporarily disturbed during construction. Permanently disturbed land would hold the wind 

22 turbines, access roads, and transmission lines. Land used for equipment laydown and turbine 

23 component assembly and erection could be returned to its original state. Given the large 

24 footprint of the wind component, land use could be affected. However, some land uses, such as 

25 agriculture, could continue once the wind turbines are operational. Land use impacts for the 

26 wind component would range from SMALL to MODERATE depending on the amount and types 

27 of land that would be affected by wind turbine construction.

28 The solar component would require 6,749 ac (2,731 ha) of land across the ROI. The majority of 

29 solar installations could be installed on building roofs at existing residential, commercial, or 

30 industrial sites or at larger standalone solar facilities, and thus, it is possible that little land would 

31 be required for construction. However, the exact magnitude of impacts on land use would 

32 depend on the amount of land that is required to be converted for construction of solar 

33 installations. Unlike wind power, solar-powered installations often cannot be colocated with 

34 existing land uses (such as in a crop-producing agricultural field). The impacts of the solar 

35 component of this alternative on land use would range from SMALL to MODERATE depending 

36 on the amount and types of land that would be affected by construction of the solar installations.

37 The NRC staff concludes that the impacts of the combination alternative on land use would be 

38 SMALL to MODERATE. This range is primarily the result of the variability in land required for 

39 the wind and solar components of the alternative.

40 4.2.6.2 Visual Resources

41 Visual resources impacts for the NGCC component of this alternative would be similar to or less 

42 than those described in Section 4.2.5 for the NGCC alternative and would, therefore, be 

43 SMALL. Visual resources would be significantly affected by construction of the wind 

44 component. Although specific effects would vary based on the topography and remoteness of 

45 the wind turbine locations, the visual impact of wind energy is often one of the most significant 
Environmental Consequences and Mitigating Actions

4-5 

1 impacts and could range from MODERATE to LARGE. The visual impacts of the solar 

2 component would also vary based on the topography of the area but are expected to be minimal 

3 because individual solar installations are not tall or expansive, and many of the installations 

4 could be constructed on building roofs at existing residential, commercial, or industrial sites. 

5 Larger standalone solar facilities could have a greater visual impact depending on the location, 

6 but the staff finds that the impacts of the solar component would likely be SMALL overall. 

7 Overall, the NRC concludes that the impacts of the combination alternative on visual resources 

8 would be SMALL to LARGE.

9 4.2.7 Purchased Power

10 4.2.7.1 Land Use

11 The purchased power alternative would have wide-ranging impacts that are hard to specifically 

12 assess because this alternative could include a mixture of coal, natural gas, nuclear, and wind 

13 across many different sites in the ROI. This alternative would likely have little to no construction 

14 impacts because it would include power from already-existing power generating facilities. The 

15 construction of additional transmission lines could affect land uses if the lines require the 

16 clearing of new transmission line corridors. The types of operational impacts would be similar to 

17 the effects discussed in the preceding alternative sections. This alternative would be more likely 

18 to intensify already-existing effects at power generating facilities than create wholly new effects 

19 on land use. Existing facilities would likely have best management practices (BMPs) and other 

20 procedures in place to ensure that effects to the environment during operations are minimized. 

21 The NRC staff concludes that the impacts on land use from the purchased power alternative 

22 would be SMALL.

23 4.2.7.2 Visual Resources

24 The purchased power alternative would not result in the construction of any buildings or facilities 

25 or any other changes to existing visual resources. Thus, the NRC staff concludes that the 

26 purchased power alternative would have no impact on visual resources, and as such, it would 

27 be SMALL.

28 4.3 Air Quality and Noise

29 This section describes the potential impacts of the proposed action (license renewal) and 

30 alternatives to the proposed action on air quality and noise conditions. 

31 4.3.1 Proposed Action

32 4.3.1.1 Air Quality

33 Section 3.3 describes the meteorological, air quality, and noise conditions in the vicinity of Byron 

34 Station. Part 51 of Title 10 of the Code of Federal Regulations (CFR), Subpart A, Appendix B, 

35 Table B-1 lists a summary of findings on National Environmental Policy Act (NEPA) issues for 

36 license renewal of nuclear power plants. Two Category 1 air quality issues are applicable to 

37 Byron Station, “air quality impacts (all plants)” and “air quality effects of transmission lines” (see 

38 Table 4–2). There are no Category 2 issues for air quality. The Category 1 issue “air quality 

39 effects of transmission lines” considers the production of ozone and oxides of nitrogen; the 

40 GEIS found that minute and insignificant amounts of ozone and nitrogen oxides are generated 

41 during transmission. The Category 1 issue “air quality impacts (all plants)” considers the air 

42 quality impacts from continued operation and refurbishment associated with license renewal. 

43 The GEIS concludes that the impact of refurbishment activities on air quality during the license 
Environmental Consequences and Mitigating Actions

4-6 

1 renewal term would be SMALL for most plants, but could be cause for concern at plants located 

2 in or near air quality nonattainment or maintenance areas (NRC 2013a).

3 Table 4–2. Air Quality and Noise

Issue GEIS Section Category

Air quality impacts (all plants) 4.3.1.1 1

Air quality effects of transmission lines 4.3.1.1 1

Noise impacts 4.3.1.2 1

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51

4 The NRC staff did not identify any new and significant information during the review of Exelon 

5 Generation Company, LLC’s (Exelon’s) ER (Exelon 2013a), the site audit, or during the scoping

6 process. As a result, no information or impacts related to these issues were identified that 

7 would change the conclusions presented in the GEIS. Therefore, there are no impacts related 

8 to these issues beyond those discussed in the GEIS. The GEIS concludes that the impact level 

9 for each of these issues is SMALL. 

10 4.3.1.2 Noise

11 One Category 1 noise issue is applicable to Byron Station, “noise impacts” (see Table 4–2). 

12 The 1996 GEIS (NRC 1996) concluded that noise was not a problem at operating plants and 

13 was not expected to be a problem at any nuclear plant during the license renewal term. The 

14 2013 GEIS (NRC 2013a) did not identify new information that would alter this conclusion; 

15 therefore, impacts are expected to be SMALL. The NRC staff did not identify any new and 

16 significant information during the review of Exelon’s ER (Exelon 2013a), the site audit, or during 

17 the scoping process. As a result, no information or impacts related to these issues were 

18 identified that would change the conclusions presented in the GEIS. Therefore, there are no 

19 impacts related to these issues beyond those discussed in the GEIS. The GEIS concludes that 

20 the impact level this issue is SMALL. 

21 4.3.2 No-Action Alternative

22 4.3.2.1 Air Quality

23 When the plant stops operating, there would be a reduction in emissions from activities related 

24 to plant operation such as cooling towers, use of stationary combustion sources (such as diesel 

25 generators, auxiliary boilers, or fire pump), and vehicle traffic (such as workers and delivery). 

26 Therefore, if emissions decrease, the impact on air quality from shutdown of the Byron Station 

27 would be SMALL.

28 4.3.2.2 Noise

29 As discussed in Section 3.3.3 of this SEIS, the NRC staff found that the predicted total 

30 (background and station contributions combined) noise levels at nearby receptors from plant 

31 operation were a little higher than U.S. Environmental Protection Agency (EPA) guideline of 55 

32 A-weighted decibels (dBA) day–night average sound level (Ldn) but well below the acceptable 

33 Department of Housing and Urban Development (HUD) Ldn guideline of 65 dBA. When the 

34 plant stops operating, there will be no noise from activities related to plant operation such as the 

35 use of cooling towers, switchyard/transformers, stationary combustion sources (such as diesel 

36 generators, auxiliary boilers, fire pump), and vehicle traffic (such as workers and delivery). In 
Environmental Consequences and Mitigating Actions

4-7 

1 other words, noise levels around the site would return to the background levels that existed 

2 before the Byron Station was built. Therefore, if noise sources are reduced, the impact on 

3 ambient noise levels would also be reduced and would be SMALL.

4 4.3.3 New Nuclear Alternative

5 4.3.3.1 Air Quality

6 This alternative includes the construction and operation of two Westinghouse AP1000 reactors, 

7 each with an approximate generating capacity of 1,200 megawatts electric (MWe). Due to the 

8 moratorium preventing the construction of new nuclear power plants within Illinois, the new 

9 nuclear alternative would have to be located elsewhere in the ROI (Indiana, Iowa, Michigan, 

10 Missouri, Kentucky, and Wisconsin). 

11 Construction of the new nuclear plant would result in temporary impacts on local air quality. 

12 During the construction phase, the primary sources of air emissions would consist of engine 

13 exhaust and fugitive dust emissions. Engine exhaust emissions would be from heavy 

14 construction equipment and commuter, delivery, and support vehicular traffic traveling within, to, 

15 and from the facility. Fugitive dust emissions would be from soil disturbances by heavy 

16 construction equipment (e.g., earthmoving, excavating, bulldozing), vehicle traffic on unpaved 

17 surfaces, concrete batch plant operations (if any), and wind erosion to a lesser extent. Air 

18 emissions include criteria pollutants (particulate matter (PM), NOx, CO, and SO2), volatile 

19 organic compounds (VOCs), hazardous air pollutants (HAPs), and greenhouse gases (GHGs). 

20 Small quantities of VOCs and HAPs emissions would be released from equipment refueling; 

21 organic solvents used in cleaning, onsite storage, and use of petroleum-based fuels; onsite 

22 maintenance of the heavy construction equipment; and certain painting and other 

23 construction-finishing activities.

24 A new nuclear plant site in the Midwest would likely be located on a relatively flat site and no 

25 heavy earthmoving activities, such as major cut-and-fill operations, would be needed. Air 

26 emissions would be intermittent and vary based on the level and duration of a specific activity 

27 throughout the construction phase. Construction lead times for nuclear plants are anticipated to 

28 be 7 years (NRC 2013a). Based on the State and Federal permits and regulated practices for 

29 managing air emissions from construction equipment and temporary stationary sources, 

30 controlling fugitive dust, and vehicle inspection and traffic management plans, the NRC staff 

31 expects that potential impacts on air quality from building a nuclear power plant would be 

32 minimal. Since air emissions from construction activities would be limited, local, and temporary, 

33 the NRC staff concludes that the overall air quality impacts associated with construction of a 

34 new nuclear alternative would be SMALL.

35 Operation of a new nuclear generating plant would result in similar air emissions to those of the 

36 existing Byron site. Nuclear power plants do not burn fossil fuels to generate electricity. 

37 Sources of air emissions include stationary combustion sources (e.g., emergency diesel 

38 generators, diesel-driven fire pumps, and auxiliary boilers), cooling towers (natural or 

39 mechanical draft cooling towers), and mobile sources (worker vehicles, onsite heavy equipment 

40 and support vehicles, and delivery of materials and disposal of wastes). Air pollutants emitted 

41 from stationary combustion sources (e.g., criteria pollutants, VOCs, HAPs, and GHGs) and from 

42 cooling towers (PM as drift) associated with operations of a nuclear power plant would be 

43 permitted in accordance with State and Federal regulatory requirements. As noted in 

44 Section 3.3, Byron maintains a Federally Enforceable State Operating Permit (also known as a 

45 “synthetic minor” air permit). A synthetic minor source has the potential to emit air pollutants in 

46 quantities at or above the major source threshold levels but has accepted Federally enforceable 

47 limitations to keep the emissions below such levels. Because air emissions would be similar for 
Environmental Consequences and Mitigating Actions

4-8 

1 a new nuclear plant, the NRC staff expects similar air permitting conditions and regulatory 

2 requirements. Subpart P of 40 CFR Part 51.307 contains the visibility protection regulatory 

3 requirements, including the review of the new sources that may affect visibility in any Federal 

4 Class I area. If a new nuclear plant were located near a mandatory Class I area, additional air 

5 pollution control requirements may be required.

6 In general, most stationary combustion sources at a nuclear power plant would operate only for 

7 limited periods, often for periodic maintenance testing. Thus, emissions from stationary 

8 combustion sources would fall far below the threshold for major sources (100 U.S. short tons (t) 

9 per year) and the threshold for mandatory GHG reporting (25,000 metric tons (MT) per year) 

10 (see Table 3–1 of this SEIS for air emissions at Byron during operation). In contrast, cooling 

11 towers would operate continuously for the entire year. However, a nuclear power plant located 

12 in the ROI would use cooling water taken from a nearby river or lake, which would have 

13 relatively low concentrations of total dissolved solids. In addition, modern cooling towers would 

14 be equipped with drift eliminators to minimize the loss of cooling water from the tower via drift. 

15 Thus, PM emissions from cooling towers would be anticipated to be minimal. The NRC staff 

16 expects similar air emissions for combustion sources from a new nuclear plant as is currently 

17 being emitted from Byron:

18 • sulfur oxides (SOx) – 0.02 t (0.02 MT) per year,

19 • nitrogen oxides (NOx) – 28 t (25 MT) per year,

20 • carbon monoxide (CO) – 7.5 t (6.8 MT) per year,

21 • particulate matter (PM2.5) – 23 t (21 MT) per year,

22 • particulate matter (PM10) – 23 t (21 MT) per year, and

23 • carbon dioxide equivalent (CO2e) – 1,501 t (1,363 MT) per year.

24 The NRC staff evaluated potential impacts on air quality associated with criteria pollutants and 

25 GHG emissions from operating a new nuclear alternative. The NRC staff determined that the 

26 impacts would be minimal. Therefore, the NRC staff concludes that the impacts of operation of 

27 a new nuclear alternative on air quality from emissions of criteria pollutants and GHGs would be 

28 SMALL.

29 The NRC staff concludes that the air quality impacts associated with construction and operation

30 of a new nuclear alternative would be SMALL. 

31 4.3.3.2 Noise

32 Construction of a new nuclear power plant is similar to that of other large industrial projects and 

33 involves many noise-generating activities. In general, noise emissions vary with each phase of 

34 construction, depending on the level of activity, the mix of construction equipment for each 

35 phase, and site-specific conditions. Noise propagation to receptors is affected by several 

36 factors, including source-receptor configuration, land cover, meteorological conditions 

37 (temperature, relative humidity, and vertical profiles of wind and temperature), and screening 

38 (such as topography, and natural or manmade barriers). Typical construction equipment, such 

39 as dump trucks, loaders, bulldozers, graders, scrapers, air compressors, generators, and mobile 

40 cranes would be used, and pile-driving and blasting activities would take place, during the 

41 construction of a new nuclear power plant. Other noise sources include commuter, delivery, 

42 and support vehicular traffic traveling within, to, and from the facility.

43 During the construction phase, a variety of construction equipment would be used and at 

44 varying duration. Noise emissions from construction equipment are predicted to be in the 85 to 

45 100 dBA range (Knauer and Pedersen 2011); however, noise levels attenuate rapidly with 
Environmental Consequences and Mitigating Actions

4-9 

1 distance such that at half a mile distance from construction equipment, 85 to 90 dBA noise 

2 levels can drop to 51 to 61 dBA (NRC 2002). Additionally, noise abatement and controls can be 

3 incorporated to reduce noise impacts. Accounting for attenuation from the construction site and 

4 noise controls, predicted noise levels can exceed EPA’s guideline of 55 dbA but be less than 

5 HUD’s acceptable noise level guideline of 65 dBA. Based on the temporary nature of 

6 construction activities, consideration of noise attenuation from the construction site to 

7 residences, the location and characteristics (i.e., ground cover), and good noise control 

8 practices, the NRC staff concludes that the potential noise impacts of construction activities

9 from a new nuclear alternative would be SMALL.

10 During the operation phase, noise sources from the new nuclear power plant would come from

11 cooling towers, transformers, turbines, pumps, compressors, other auxiliary equipment such as 

12 standby generators or auxiliary boilers, and vehicular traffic (commuting, delivery, and support), 

13 similar to those for Byron discussed in Section 3.3.3 of this SEIS. Noise level estimates at 

14 four receptors around Byron and the nearest residence located more than 0.9 km (0.6 mi) from 

15 primary noise sources (see Section 3.3.3 of this SEIS), ranged between 50 and 57 dBA Ldn, 

16 considering both the background and station contributions.

17 Although the plant layout and the distance from primary noise sources to the nearby receptors

18 at Byron might be different from those at a new nuclear alternative, the NRC staff does not 

19 expect noise impacts for a new nuclear plant to be any greater than that analyzed for the 

20 existing Byron site. Therefore, the noise impacts of a new nuclear plant located within the ROI 

21 region would be SMALL.

22 The NRC staff concludes that the noise impacts associated with operation and construction of a 

23 new nuclear alternative would be SMALL.

24 4.3.4 IGCC Alternative

25 4.3.4.1 Air Quality

26 This alternative includes the construction and operation of four IGCC units with a total output of 

27 2,472 MWe and a capacity factor of 85 percent. The new power plant is assumed to be located 

28 at existing power plant site(s). These sites could be located in Illinois (including the Byron site) 

29 or other adjoining states in the ROI (Indiana, Iowa, Michigan, Missouri, Kentucky, and 

30 Wisconsin). New infrastructure and infrastructure upgrades would depend on specific site 

31 locations.

32 Construction of an IGCC plant would be similar to that of other large industrial projects and 

33 involves many activities similar to those for a new nuclear alternative presented in Section 4.3.3. 

34 Construction of an IGCC plant would result in the release of various criteria pollutants (PM, NOx, 

35 CO, and SO2), VOCs, HAPs, and GHGs from operation of internal combustion engines in 

36 construction vehicles, equipment, delivery vehicles, and vehicles used by the commuting 

37 construction workforce. In addition, soil disturbance activities such as earthmoving and material 

38 handling would generate fugitive dust. The onsite storage and dispensing of vehicle and 

39 equipment fuels result in VOC releases. Air emissions would be intermittent and vary based on 

40 the level and duration of a specific activity throughout the construction phase. Construction lead 

41 times for IGCC plants are estimated to be 3 years (NETL 2013b). Impacts would be localized, 

42 intermittent, and short-lived, and adherence to well-developed and well-understood construction 

43 BMPs would mitigate such impacts. The NRC staff concludes that construction-related impacts 

44 on air quality from an IGCC alternative would be of relatively short duration and would be 

45 SMALL.
Environmental Consequences and Mitigating Actions

4-10

1 The sources of air emissions during operation include heat recovery steam generator (HRSG) 

2 stacks, the wet gas sulfuric acid (WSA) system exhaust, acid gas removal process 

3 startup/shutdown vents, startup stacks, flares, material handling equipment, and mechanical 

4 draft cooling towers (DOE 2010a). The HRSG stacks would release the most emissions. 

5 Auxiliary boilers and firewater pumps would also generate emissions on an infrequent basis. 

6 Compared to conventional coal-fired power plants, the proposed IGCC power plant would 

7 reduce sulfur dioxide, nitrogen oxides, mercury, and PM emissions by removing constituents 

8 from the syngas (DOE 2010a). The IGCC alternative would also result in lower nitrogen oxide

9 emissions since nearly 100 percent of the fuel-bound nitrogen from the syngas would be 

10 removed from the syngas before combustion in the gas turbine. Sulfur removal technology 

11 would remove more than 99 percent of the sulfur in the syngas. The use of sulfide-activated 

12 carbon could remove more than 92 percent of mercury from the syngas. More than 

13 99.9 percent of particulate emissions would be removed from the syngas using 

14 high-temperature, high-pressure filtration.

15 Various Federal and state regulations aimed at controlling air pollution would affect an IGCC 

16 alternative located in the seven-state ROI. A new IGCC plant would qualify as a new major 

17 source because of its potential to emit (PTE) greater than 100 t per year of criteria pollutants, 

18 and would be subject to New Source Review (NSR) permitting program requirements under the 

19 Clean Air Act (CAA) (EPA 2013d). An NSR permit or construction permit would specify 

20 emission limits for each pollutant, along with monitoring and reporting requirements, 

21 specifications for fuel and control equipment, and monitoring and performance testing for the 

22 IGCC units, auxiliary boiler, and WSA process. The new IGCC plant would be required to 

23 secure a Title V operating permit from the state agency.

24 An NSR review would limit emissions for criteria pollutants and would reflect existing ambient air 

25 quality at the selected location. Because the IGCC alternative could be located anywhere within 

26 the seven-state ROI, it is unknown at this time whether or not the specific site(s) would be 

27 located within a designated attainment area. For instance, if the IGCC alternative were to be 

28 located at the Byron site, Ogle County is designated as an attainment/unclassifiable area for all 

29 criteria pollutants (40 CFR 81.314). Analysis regarding National Ambient Air Quality Standards 

30 (NAAQS) compliance would be conducted at the specific site location. The IGCC alternative 

31 also would need to comply with the standard of performance for new stationary sources set forth 

32 in 40 CFR Part 60, Subpart Da, “Standards of performance for electric utility steam generating 

33 units.”

34 If the IGCC alternative were located close to a mandatory Class I area, additional air pollution 

35 control requirements would be necessary (Subpart P of 40 CFR Part 51) as mandated by the 

36 Regional Haze Rule. Within the ROI, there are five Class I Federal areas, including: Mammoth 

37 Cave National Park (NP) in Kentucky (40 CFR 81.411), Isle Royale NP and Seney Wilderness 

38 Area (WA) in Michigan (40 CFR 81.414), and Hercules-Glades WA and Mingo WA in Missouri

39 (40 CFR 81.416). The rule could apply to the IGCC alternative, but would depend on specific 

site locations(s). If the IGCC alternative were to be located at the Byron site, the nearest 5 40

41 Class I Federal area for visibility protection is the Seney WA in Michigan (40 CFR 81.414), 

42 about 520 km (323 mi) north-northeast of the Byron site.

 

5 Rainbow Lake in Wisconsin is a Mandatory Federal Class I area where visibility is not an important air quality related value. In 

1980 Rainbow Lake was excluded for purposes of visibility protection as a Class I area. Rainbow Lake is approximately 505 km

(314 mi) north-northwest of the Byron site. 
Environmental Consequences and Mitigating Actions

4-11

1 Air emissions for the IGCC alternative were estimated based on data presented in Table 4.3-1 

2 in the GEIS (NRC 2013a). The resulting IGCC emissions are estimated to be as follows:

3 • sulfur dioxide (SO2)—820 t (740 MT) per year, 

4 • nitrogen oxides (NOx)—3,000 t (2,720 MT) per year, 

5 • particulate matter (PM10)—480 t (435 MT) per year, 

6 • carbon monoxide (CO)—2,045 t (1,850 MT) per year, and

7 • carbon dioxide equivalent (CO2e)—14.3 million t (13.0 million MT) per year. 

8 The IGCC alternative would produce 820 t (740 MT) per year of sulfur dioxide and 3,000 t 

9 (2,072 MT) per year of nitrogen oxides. The IGCC plant would have to comply with Title IV of 

10 the CAA (42 USC § 7651) reduction requirements for sulfur oxides and nitrogen oxides, which 

11 are the main precursors of acid rain and the major causes of reduced visibility. Title IV 

12 establishes maximum sulfur oxide and nitrogen oxide emission rates from the existing plants 

13 and a system of sulfur oxide emission allowances that can be used, sold, or saved for future use 

14 by the new plants. The new plant would be subjected to the continuous monitoring 

15 requirements of sulfur dioxide and nitrogen oxides as specified in 40 CFR Part 75. The Clean 

Air Interstate Rule 6 16 (CAIR) requires 27 states (including Indiana, Iowa, Michigan, Missouri, 

17 Kentucky, and Wisconsin) to improve air quality requiring power plants to reduce sulfur dioxide

18 and nitrogen oxide emissions (EPA 2014a). A new IGCC plant would be subject to these 

19 additional rules and regulations.

20 The IGCC alternative would emit approximately 14.3 million t (approximately 13 million MT) per 

21 year of CO2e emissions. The plant would be subjected to the continuous monitoring 

22 requirements for carbon dioxide, as specified in 40 CFR Part 75. On July 12, 2012, EPA issued 

23 a final rule tailoring the criteria that determine which stationary sources and modifications to 

24 existing projects become subject to permitting requirements for GHG emissions under the 

25 prevention of significant deterioration (PSD) and Title V Federal permit programs of the CAA

(77 FR 41051). Beginning January 2, 20117 26 , operating permits issued to major sources of GHG 

27 under the PSD or Title V permit programs must contain provisions requiring the use of best 

28 available control technology (BACT) to limit the emissions of GHGs if those sources would be 

29 subject to PSD or Title V permitting requirements because of their non-GHG pollutant emission 

30 potentials and their estimated GHG emissions are at least 75,000 tons/yr of CO2e. If the IGCC 

31 alternative meets PSD or Title V permitting requirements for non-GHG pollutant emissions and 

32 the GHG emission thresholds established in the rule, then GHG emissions from this alternative 

33 would be regulated under the PSD and Title V permit programs.

 

6 The Clean Air Interstate Rule (CAIR) was first issued by EPA in 2005; however, the Federal rule was vacated by the D.C. Circuit 

Court on February 8, 2008. In December 2008, the U.S. Court of Appeals for the D.C. Circuit reinstated the rule, allowing it to 

remain in effect but also requiring EPA to revise the rule and its implementation plan. On July 6, 2010, EPA proposed replacing 

CAIR with the Cross-State Air Pollution Rule (CSAPR) for control of sulfur dioxide and nitrogen oxide emissions that cross state 

lines, the regulations of which would be implemented in 2011 and finalized in 2012. However, CSAPR was vacated by the 

D.C. Circuit Court on August 21, 2012. On April 29, 2014, the U.S. Supreme Court reversed the D.C. Circuit opinion vacating 

CSAPR. EPA is reviewing the opinion and CAIR remains in effect. 

7 On June 23, 2014, the U.S. Supreme Court issued a decision that the EPA may not treat GHGs as an air pollutant for purposes of 

determining whether a source is a major source required to obtain a PSD or Title V permit, but could continue to require PSD and 

Title V permits otherwise required based on emissions of conventional pollutants. In July 2014, the EPA issued a memorandum in 

response to the Supreme Court’s decision and acknowledged that while the decision is pending judicial action, the EPA will no

longer require PSD or Title V permits for GHG-emitting sources that are not sources subject to PSD or Title V permits based on 

emissions of conventional pollutants (nitrogen oxides, carbon monoxide, etc.) (EPA 2014b).
Environmental Consequences and Mitigating Actions

4-12

1 In response to the Consolidated Appropriations Act of 2008 (Public Law 110-161), EPA issued 

2 final mandatory GHG reporting regulations for major sources effective in December 2009 

3 (EPA 2012b). Major sources are defined as those emitting more than 25,000 t per year of all 

4 GHGs. An IGCC alternative would be subject to these reporting regulations with or without 

5 carbon capture. On January 8, 2014, EPA issued a new proposal for GHG emissions from new 

6 fossil fuel-fired electric utility steam generating units (79 FR 1430). It also proposes standards 

7 of performance for IGCC units that burn coal. The performance standards are based on partial 

8 implementation of carbon capture and sequestration (CCS) as the best system of emission 

9 reduction (BSER). Although the proposed rule has not been finalized, the IGCC alternative 

10 analysis includes an option for future implementation of CCS.

11 An IGCC alternative also would be subject to the Mercury and Air Toxics Standards (MATS) 

12 final rule, finalized by EPA on December 16, 2011 (EPA 2012a). Standards for emissions of 

13 heavy metals (mercury, arsenic, chromium, and nickel) and acid gases (hydrochloric acid and 

14 hydrofluoric acid) are set by MATS. Mercury is the most prominent HAP emitted and is subject 

15 to regulation by the MATS rule. New IGCC units are required to meet a mercury emission limit 

16 of 0.003 lb per gigawatt-hour (40 CFR Part 63 Subpart UUUUU). NRC staff estimates that an 

17 IGCC alternative replacing the electrical output of Byron would generate 0.03 t (0.02 MT) of 

18 mercury per year.

19 The impact from sulfur dioxide and nitrogen oxide emissions would be significant and subject to 

20 a Title V permit. GHG emissions also would be noticeable and significant; GHG emissions 

21 would be much larger than the threshold in EPA’s GHG Tailoring Rule and GHG emissions may 

22 be regulated under the PSD and Title V permit programs. that would trigger a regulated NSR. 

23 In the near future, carbon dioxide emissions could be reduced considerably if CCS technology 

24 were installed. The NRC staff concludes that the air quality impacts associated with operation 

25 of an IGCC alternative would be MODERATE. 

26 The NRC staff concludes that the overall air quality impacts associated with construction and

27 operation of an IGCC alternative would be MODERATE. 

28 4.3.4.2 Noise

29 Construction of an IGCC plant is similar to that of other large industrial projects, and

30 construction-related noise sources would be virtually the same as those for construction of the 

31 nuclear alternative. However, the construction period for the IGCC alternative would be shorter 

32 and the level of activities scattered over a wide area would be less extensive compared with 

33 construction of a nuclear alternative. Consequently, with construction-related noise for the 

34 nuclear alternative as a bounding condition, the NRC staff concludes that construction-related 

35 noise associated with the IGCC alternative would be SMALL.

36 Operation of an IGCC plant would introduce mechanical sources of noise that would be audible 

37 off site. Continuous sources include the mechanical equipment associated with normal plant 

38 operations and mechanical draft cooling towers. Intermittent sources include the equipment 

39 related to coal handling, solid waste disposal, transportation related to coal and lime/limestone 

40 delivery, use of outside loudspeakers, and the commuting of plant employees. Noise 

41 associated with rail delivery of coal and lime/limestone would extend beyond the plant site 

42 boundary and would be most significant for residents living in the vicinity of the facility and along 

43 the rail route. Noise impacts associated with rail delivery are predicted to be in the 80 to 96 dBA 

44 range (NRC 2002). Transportation-related noise sources have the potential to impact as these 

45 noise sources reach beyond the plant site boundary. The NRC staff concludes that the potential 

46 impacts of noise on residents in the vicinity of the facility of an IGCC alternative and the rail line 

47 are considered to range from SMALL to MODERATE, depending on the distance from primary 

48 noise sources to nearby sensitive receptors.
Environmental Consequences and Mitigating Actions

4-13

1 The NRC staff concludes that the overall potential impacts of noise associated with construction 

2 and operation of the IGCC alternative and the rail line are considered to range from SMALL to 

3 MODERATE. 

4 4.3.5 NGCC Alternative

5 4.3.5.1 Air Quality

6 This alternative includes the construction and operation of five NGCC 560-MWe units (total 

7 2,800 MWe) and a capacity factor of 85 percent. These sites could be located at an existing 

8 power plant site in the ROI (including the Byron site). Some infrastructure upgrades may be 

9 required and would require construction of a new or upgraded pipeline. Using existing power 

10 plant sites maximizes availability of infrastructure and reduces disruption to land and 

11 populations.

12 Construction of an NGCC power plant would be similar to that of other large industrial projects. 

13 Construction of an NGCC power plant would result in the release of various criteria pollutants 

14 (PM, NOx, CO, and SO2), VOCs, HAPs, and GHGs from the operation of internal combustion 

15 engines in construction vehicles, equipment, delivery vehicles, and vehicles used by the 

16 commuting construction workforce. In addition, onsite soil disturbance activities such as 

17 earthmoving and material handling would generate fugitive dust. Releases of VOCs will also 

18 result from the onsite storage and dispensing of vehicle and equipment fuels. Air emissions 

19 would be intermittent and vary based on the level and duration of a specific activity throughout 

20 the construction phase. Gas-fired power plants are constructed relatively quickly; construction 

21 lead times for NGCC plants are around 2 to 3 years (EIA 2011; OECD/NEA 2005). Impacts 

22 would be localized, intermittent, and short-lived, and adherence to well-developed and 

23 well-understood construction BMPs would mitigate such impacts. Therefore the NRC staff 

24 concludes that construction-related impacts on air quality from an NGCC alternative would be of 

25 relatively short duration and would be SMALL.

26 Operation of the NGCC plant would result in significant emissions of certain criteria pollutants, 

27 including carbon monoxide, nitrogen oxides, and PM. The sources of air emissions during 

28 operation include gas turbines through HRSG stacks and mechanical draft cooling towers. 

29 Auxiliary boilers and emergency generators would also generate emissions on an infrequent 

30 basis.

31 The NGCC alternative could be located anywhere within the seven-state ROI; it is therefore 

32 unknown at this time whether or not the specific site(s) would be located within a designated 

33 attainment area. For instance, if the NGCC alternative were to be located at the Byron site, 

34 Ogle County is designated as an attainment/unclassifiable area for all criteria pollutants 

35 (40 CFR 81.314). Analysis regarding NAAQS compliance would be conducted at the specific 

36 site location. Various Federal and state regulations aimed at controlling air pollution would 

37 affect an NGCC alternative located in the seven-state ROI. An NGCC plant would be subject to 

38 NSR permitting program requirements to ensure air emissions are minimized and the local air 

39 quality is not substantially degraded (EPA 2013d). The new NGCC plant would be required to 

40 secure a Title V operating permit from the state agency. The NGCC plant would need to comply 

41 with the standards of performance for stationary combustion turbines set forth in 40 CFR 

42 Part 60 Subpart KKKK. If the NGCC alternative were located close to a mandatory Class I area, 

43 additional air pollution control requirements would be required (Subpart P of 40 CFR Part 51) as 

44 mandated by the Regional Haze Rule. A detailed discussion of these Federal and state 

45 regulations is provided in Section 4.3.4.1 (see Air Quality Operation discussion for the IGCC

46 alternative). 
Environmental Consequences and Mitigating Actions

4-14

1 Air emissions for the NGCC alternative were estimated based on data presented in Table 4.3-2 

2 in the GEIS (NRC 2013a) and EPA emission factors (EPA 2000; NRC 2013a). The estimate is 

3 based on using advanced F class gas turbines at one or multiple sites within the ROI. The 

4 resulting NGCC emissions are estimated to be as follows:

5 • sulfur dioxide (SO2)—380 t (350 MT) per year, 

6 • nitrogen oxides (NOx)—600 t (540 MT) per year, 

7 • particulate matter (PM10)—210 t (190 MT) per year, 

8 • carbon monoxide (CO)—1,690 t (1,530 MT) per year, and

9 • carbon dioxide equivalent (CO2e)—7.9 million t (7.2 million MT) per year. 

10 The NGCC alternative would produce 380 t (350 MT) per year of sulfur dioxide and 600 t 

11 (540 MT) per year of nitrogen oxides based on the use of dry low-nitrogen-oxide combustion 

12 technology coupled with use of selective catalytic reduction (SCR) to significantly reduce 

13 nitrogen oxide emissions (NETL 2013b). The new plant would be subjected to the continuous 

14 monitoring requirements of sulfur dioxide and nitrogen oxides as specified in 40 CFR Part 75. 

15 The CAIR requires 27 states (including Indiana, Iowa, Michigan, Missouri, Kentucky, and 

16 Wisconsin) to improve air quality, requiring power plants to reduce sulfur dioxide and nitrogen 

17 oxide emissions (EPA 2014a). A new NGCC plant would be subject to these additional rules 

18 and regulations.

19 The NGCC alternative would emit approximately 7.9 million t (approximately 7.2 million MT) per 

20 year of CO2e. The plant would be subjected to the continuous monitoring requirements for 

21 carbon dioxide, as specified in 40 CFR Part 75. On July 12, 2012, EPA issued a final rule 

22 tailoring the criteria that determine which stationary sources and modifications to existing 

23 projects become subject to permitting requirements for GHG emissions under the PSD and 

Title V Programs of the CAA (77 FR 41051). Beginning January 2, 20118 24 , operating permits 

25 issued to major sources of GHG under PSD or Title V Federal permit programs must contain 

26 provisions requiring the use of best available control technology (BACT) to limit the emissions of 

27 GHGs if those sources would be subject to PSD or Title V permitting requirements because of 

28 their non-GHG pollutant emission potentials and their estimated GHG emissions are at least 

29 75,000 tons/yr of CO2 equivalents (CO2e). If the NGCC alternative meets PSD or Title V 

30 permitting requirements for non-GHG pollutant emissions and the GHG emission thresholds 

31 established in the rule, then GHG emissions from this alternative would be regulated under the 

32 PSD and Title V permit programs.

33 In response to the Consolidated Appropriations Act of 2008 (Public Law 110-161), EPA issued 

34 final mandatory GHG reporting regulations for major sources effective in December 2009 

35 (EPA 2012b). Major sources are defined as those emitting more than 25,000 t per year of all 

36 GHGs. An NGCC alternative would be subject to these reporting regulations with or without 

37 carbon capture.

 

8 On June 23, 2014, the U.S. Supreme Court issued a decision that the EPA may not treat GHGs as an air pollutant for purposes of 

determining whether a source is a major source required to obtain a PSD or Title V permit, but could continue to require PSD and 

Title V permits otherwise required based on emissions of conventional pollutants. In July 2014, the EPA issued a memorandum in 

response to the Supreme Court’s decision and acknowledged that while the decision is pending judicial action, the EPA will no

longer require PSD or Title V permits for GHG-emitting sources that are not sources subject to PSD or Title V permits based on 

emissions of conventional pollutants (nitrogen oxides, carbon monoxide, etc.) (EPA 2014b).
Environmental Consequences and Mitigating Actions

4-15

1 On January 8, 2014, EPA issued a new proposal for GHG emissions from new fossil fuel-fired 

2 electric utility steam generating units (79 FR 1430). It also proposes standards of performance 

3 for natural gas-fired stationary combustion turbines based on modern, efficient NGCC

4 technology as the BSER. 

5 In December 2000, EPA issued regulatory findings on emissions of HAPs from electric utility 

6 steam-generating units (65 FR 79825). These findings indicated that natural gas-fired plants 

7 emit HAPs such as arsenic, formaldehyde, and nickel and stated that: 

8 ...the impacts due to HAP emissions from natural gas-fired electric utility steam 

9 generating units were negligible based on the results of the study. The 

10 Administrator finds that regulation of HAP emissions from natural gas-fired 

11 electric utility steam generating units is not appropriate or necessary. 

12 [65 FR 79825]

13 Mercury is not emitted from NGCC power plants due to the lack of mercury in natural gas used 

14 as fuel.

15 Considerable air emissions are emitted from operations of the NGCC alternative. The impacts 

16 from nitrogen oxide emissions would be significant and subject to a Title V permit. GHG 

17 emissions also would be noticeable and significant; carbon dioxide emissions would be much 

18 larger than the threshold in EPA’s GHG Tailoring Rule. The NRC staff concludes that the 

19 overall air quality impacts associated with operation of an NGCC alternative would be 

20 MODERATE.

21 The NRC staff concludes that the overall air quality impacts associated with construction and 

22 operation of an NGCC alternative would be MODERATE.

23 4.3.5.2 Noise

24 The construction-related noise sources for an NGCC alternative would be virtually the same as 

25 those for construction of the IGCC alternative. Construction vehicles and equipment associated 

26 with the construction of the NGCC plant would generate noise; these impacts would be 

27 intermittent and last only through the duration of plant construction. Noise emissions from 

28 common construction equipment would be in the 85 to 100 dBA range (Knauer and 

29 Pedersen 2011). However, noise abatement and controls can be incorporated to reduce noise 

30 impacts. The review team concludes that construction-related noise impacts associated with 

31 the NGCC alternative would be SMALL.

32 Noise impacts from operations would include cooling towers (water pumps, cascading water, or 

33 fans), transformers, turbines, pumps, compressors, exhaust stacks, the combustion inlet filter 

34 house, condenser fans, high-pressure steam piping, and vehicles (Saussus 2012). Pipelines 

35 delivering natural gas fuel could be audible off site near gas compressor stations, but such 

36 noise impacts would be similar to impacts already occurring in the vicinity of the existing pipeline 

37 to which the new NGCC site would connect. Most noise-producing equipment is located inside 

38 the power block buildings and no outside fuel-handling activities will occur. Minor offsite noise 

39 sources could include pipeline compressor stations. The NRC staff concludes that 

40 operation-related noise impacts from the NGCC alternative would be SMALL.

41 The NRC staff concludes that construction operation-related noise impacts from the NGCC 

42 alternative would be SMALL.

43 4.3.6 Combination Alternative (NGCC, Wind, Solar)

44 The combination alternative relies on NGCC, wind, and solar generating capacity. The total 

45 installed solar photovoltaic (PV) capacity is 1,193 megawatts (MW), the total installed wind 
Environmental Consequences and Mitigating Actions

4-16

1 capacity is 6,042 MW of onshore wind, and the total installed capacity for NGCC is 267 MW in 

2 this alternative. All portions of the combination alternative would be located in Illinois or other 

3 adjoining states in the ROI (Indiana, Iowa, Michigan, Missouri, Kentucky, and Wisconsin).

4 The NGCC alternative would require one 267-MW unit. For the NGCC portion of the 

5 combination alternative, it is assumed that sites would be located at an existing power plant site 

6 which maximizes availability of existing infrastructure and reduces disruption to land and 

7 populations. Most of the wind farms would likely be located on open agricultural cropland, 

8 which would remain largely unaffected by the wind turbines. The solar portion requires 

9 1,193 MW, and it is assumed that some of the capacity would be from small units and may be 

10 installed on building roofs or on existing residential, commercial, or industrial sites.

11 4.3.6.1 Air Quality

12 Air emissions associated with the construction of the NGCC portion of the combination 

13 alternative are similar to the NGCC alternative but reduced considerably because its electricity 

14 output is approximately 10 percent that of the NGCC alternative. As discussed in 

15 Section 4.3.5.1, construction activities for an NGCC alternative would cause some temporary 

16 impacts to air quality from dust generation during operation of the earthmoving and material 

17 handling equipment and exhaust emissions from worker vehicles and construction equipment. 

18 These emissions include criteria pollutants, VOCs, GHGs, and small amounts of HAPs. 

19 However, these impacts would be localized, intermittent, and short-lived, and adherence to 

20 well-developed and well-understood construction BMPs would mitigate such impacts. The NRC 

21 staff concludes that construction-related impacts on air quality from an NGCC portion of the 

22 combination alternative would be of relatively short duration and would be SMALL.

23 For the wind portion of the combination alternative, only a small percentage of site land 

24 (5 percent or less) would be disturbed by construction activities because wind turbines need to 

25 be separated from one another in order to maximize energy production and avoid wake 

26 turbulences created by upwind turbines. Construction of the wind portion of the combination 

27 alternative would involve a number of activities, including road and staging/laydown area 

28 construction, land clearing, topsoil stripping, earthmoving operations, grading, ground 

29 excavation, drilling, foundation treatment, wind turbines erection, ancillary building/structure 

30 construction, and electrical and mechanical installation. For most wind energy facilities, the site 

31 preparation phase would last for only a few months, followed by a year-long construction phase 

32 (depending on size of the wind energy facility) (Tegen 2006). Air emissions associated with 

33 construction activities result from fugitive dust from soil disturbances and engine exhaust from 

34 heavy equipment and vehicular traffic. These emissions include criteria pollutants, VOCs, 

35 GHGs, and HAPs. Dust suppression methods and other mitigation measures could reduce 

36 impacts from fugitive dust. The wind portion of the combination alternative would have no 

37 power block, for which intensive construction activities would occur. Accordingly, the number of 

38 heavy equipment and workforce, level of activities, and construction duration would be 

39 substantially lower than other alternatives. Therefore, the NRC staff concludes that the overall 

40 air quality impacts associated with construction of the wind portion of the combination 

41 alternative would be SMALL.

42 Construction of the solar portion of the combination alternative would cause temporary impacts 

43 to air quality from fugitive dust from soil disturbances and engine exhaust from heavy equipment 

44 and from vehicular traffic. Air emissions associated with construction activities include criteria 

45 pollutants, VOCs, GHGs, and HAPs to a lesser amount. Dust suppression methods and other 

46 mitigation measures could reduce impacts from fugitive dust. The solar PV portion of the 

47 combination alternative would have no power block, for which intensive construction activities 

48 would occur. Accordingly, the number of heavy equipment and workforce, level of activities, 
Environmental Consequences and Mitigating Actions

4-17

1 and construction duration would be substantially lower than those for other alternatives. 

2 Therefore, the NRC staff concludes that the overall air quality impacts associated with 

3 construction of the solar PV portion of the combination alternative would be SMALL.

4 Air emissions associated with the operation of the NGCC portion of the combination alternative 

5 are similar to the NGCC alternative in Section 4.3.5.1 but reduced proportionally because its 

6 electricity output is approximately 13 percent that of the NGCC alternative.

7 Air emissions for the NGCC alternative were estimated based on data presented in Table 4.3-2 

8 in the GEIS (NRC 2013a) and Energy Information Administration (EIA) emission factors 

9 (EIA 1999; NRC 2013a). The estimate is based on using advanced F class gas turbines at one 

10 or multiple sites within the ROI. The resulting NGCC emissions are estimated to be as follows:

11 • sulfur dioxide (SO2)—50 t (45 MT) per year, 

12 • nitrogen oxides (NOx)—80 t (70 MT) per year, 

13 • particulate matter (PM10)—30 t (25 MT) per year, 

14 • carbon monoxide (CO)—220 t (200 MT) per year, and

15 • carbon dioxide equivalent (CO2e)—1.0 million t (0.9 million MT) per year. 

16 Annual emissions of sulfur dioxide and nitrogen oxides would be lower than the major source 

17 threshold, while those of carbon monoxide would exceed the major source threshold. The 

18 overall air quality impacts associated with operation of the NGCC portion of the combination 

19 alternative would be SMALL to MODERATE.

20 Emissions from the operation of wind energy facilities would include minor dust and engine 

21 exhaust emissions from vehicles and heavy equipment associated with site inspections, 

22 maintenance activities, and wind erosion from cleared land and access roads. The types of 

23 emission sources and pollutants during operation would be similar to those during construction, 

24 but much fewer emissions would be released during operation. The NRC staff concludes that 

25 the overall air quality impacts associated with the operation of the wind portion of the 

26 combination alternative would be SMALL.

27 In general, air emissions associated with the operation of solar energy facilities are negligible 

28 because no fossil fuels are burned to generate electricity. Emissions from solar fields would 

29 include fugitive dust and engine exhaust emissions from vehicles and heavy equipment 

30 associated with site inspections, maintenance activities (panel washing or replacement), and 

31 wind erosion from cleared lands and access roads. The types of emission sources and 

32 pollutants during operation would be similar to those during construction, but much fewer 

33 emissions would be released during operation. These emissions should not cause 

34 exceedances of air quality standards or have any impacts on climate change. The NRC staff 

35 concludes that the overall air quality impacts associated with the operation of the solar PV 

36 portion of the combination alternative would be SMALL.

37 The overall air quality impacts associated with construction and operation of the combination 

38 alternative would be SMALL to MODERATE. 

39 4.3.6.2 Noise

40 The construction-related noise sources for the NGCC portion of the combination alternative

41 would be virtually the same as those for construction of the NGCC alternative. The construction 

42 period for the NGCC portion would be shorter and the level of construction activities would be 

43 less extensive than the NGCC alternative. Consequently, the NRC staff concludes that 
Environmental Consequences and Mitigating Actions

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1 construction-related noise associated with the NGCC portion of the combination alternative 

2 would be SMALL.

3 Construction of the wind portion of the combination alternative would involve a number of 

4 activities, as described above. The wind portion of the combination alternative would have no 

5 power block, for which intensive construction activities would occur. Accordingly, the number of 

6 heavy equipment and workforce, level of activities, and construction duration would be 

7 substantially lower than other alternatives. Considering these factors, the NRC staff concludes

8 that construction-related noise associated with the wind portion of the combination alternative 

9 would be SMALL.

10 Construction of the solar PV portion of the combination alternative would involve a number of 

11 activities. The solar PV portion of the combination alternative would have no power block, for 

12 which intensive construction activities would occur. Accordingly, the number of heavy 

13 equipment and workforce, level of activities, and construction duration would be substantially 

14 lower than other alternatives. Considering these factors, the NRC staff concludes that 

15 construction-related noise associated with the solar PV portion of combination alternative would 

16 be SMALL.

17 Besides noise from the power block area, cooling towers, and vehicular traffic, operation-related 

18 noise for the NGCC portion would include limited outdoor waste handling activities. Pipelines 

19 delivering natural gas fuel could be audible off site near gas compressor stations, but such 

20 sound impacts would be similar to impacts already occurring in the vicinity of the existing 

21 pipeline to which the new NGCC site would connect. Most noise-producing equipment is 

22 located inside the power block buildings, and no outside fuel-handling activities would occur. 

23 Minor offsite noise sources could be pipeline compressor stations. The NRC staff concludes 

24 that operation-related noise from the NGCC portion of the combination alternative would be 

25 SMALL.

26 Noise impacts from wind generation operations would include aerodynamic noise from the 

27 turbine rotors and mechanical noise from the turbine drivetrain components. Noise levels are 

28 dependent on the wind and atmospheric conditions, which vary with time, and on site-specific 

29 conditions, including: the number and size of wind turbines, their layout, distance to nearby 

30 sensitive receptors, land cover, and topography. Wind turbine noise levels can reach 105 dBA; 

31 however, studies show that at approximately 1,000 ft (300 m) from a wind turbine, noise levels 

32 can reach 43 dBA (GE 2010; Hessler 2011). Therefore, masking effects of background noise 

33 should be taken into consideration. Unless noise from wind turbines is masked by high 

34 background levels (e.g., near major highways or industrial complexes), it can be noticeable and 

35 annoying at farther distances. One study indicated that, for the same A-weighted sound level, 

36 proportions of respondents annoyed by wind turbine noise are higher than for other community 

37 noise, such as aircraft, road, or railway traffic, and that the proportion annoyed increases more 

38 rapidly (Pedersen and Persson Waye 2004). Therefore, the NRC staff concludes that 

39 operation-related noise from the wind portion of the combination alternative would be SMALL to

40 MODERATE, depending on the layout and location of the wind facility and the distance to 

41 nearby sensitive receptors.

42 The solar PV portion of the combination alternative would have no power block and cooling 

43 towers, and thus there would be a minimal number of noise sources with low-level noises. 

44 Noise sources include small-scale cooling systems to dissipate heat from solar module 

45 assemblies, solar tracking devices, inverters, transformers, and vehicle traffic for maintenance 

46 and inspection. Because of minimal noise-generating activities, noise from a solar PV facility 

47 would be anticipated to be inaudible or barely perceptible at the facility boundaries. Considering 

48 the minimum number of sources with low-noise levels and the area size of the solar PV facility, 
Environmental Consequences and Mitigating Actions

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1 the NRC staff concludes that operation-related noise from the solar PV portion of the 

2 combination alternative would be SMALL.

3 The noise impacts associated with construction and operation of the combination alternative 

4 would be SMALL to MODERATE. 

5 4.3.7 Purchased Power

6 4.3.7.1 Air Quality

7 As discussed in Section 2.2.2.5, purchased power would come from common types of existing 

8 technology (coal, natural gas, and nuclear) within the ROI, and it is not likely that new facilities 

9 would be constructed to replace Byron. Construction of new transmission lines would result in 

10 additional amounts of air emissions. Air emissions associated with the construction of 

11 transmission lines would be from operation of the earthmoving and material handling equipment 

12 and exhaust emissions from worker vehicles and construction equipment. These emissions 

13 include criteria pollutants, VOCs, GHGs, and HAPs. However, these impacts would be 

14 temporary and not likely to be high. For purchased power from existing plants, the impacts on 

15 air quality are expected to be SMALL as there would be minimal change in existing plant 

16 operations.

17 If new facilities were to be constructed for purchased power, the impact on air quality would 

18 depend on the plant technology constructed, since air emissions can vary substantially, as can 

19 be observed from the alternative air quality discussions provided above. For instance, natural 

20 gas- and coal-fired plants emit higher amounts of nitrogen oxides, sulfur oxides, PM, and carbon 

21 dioxide than nuclear plants. Purchased power from new nuclear plants would not have 

22 noticeable impacts on air quality. New natural gas- and coal-fired plants would have noticeable 

23 impacts on air quality as a result of the higher amounts of air emissions.

24 Therefore, impacts on air quality from purchased power of new plants would be SMALL to 

25 MODERATE.

26 4.3.7.2 Noise

27 Purchased power from existing electricity generating facilities would not have noticeable 

28 impacts on noise as there would be minimal change in existing plant operations. Purchased 

29 power from new generating facilities could have impacts on noise. Construction and operation 

30 of new facilities could result in additional noise sources including mechanical equipment 

31 associated with normal plant operations and vehicular traffic. Additionally, construction of new 

32 transmission lines could increase noise levels. Increase in noise levels from construction of 

33 new transmission lines and new facilities would be dependent on the distance of residents to the 

34 noise sources. Noise levels from operation will also be dependent on the type of technology, for 

35 instance, operation of nuclear or wind power. Therefore, impacts from purchased power on 

36 noise would be SMALL to MODERATE.

37 4.3.8 Conclusions 

38 Air Quality

39 Estimated air emissions from operations of the proposed action and five alternatives are 

40 presented in Table 4–3. Air emissions from the proposed action and the new nuclear alternative 

41 would be lowest, while the IGCC alternative would release the highest emissions, followed by 

42 the NGCC alternative. Air emissions from the combination alternative would fall between the 

43 nuclear alternative and the NGCC alternative. It is apparent that the IGCC and NGCC 

44 alternatives will produce significantly greater air pollutant emissions than those associated with 
Environmental Consequences and Mitigating Actions

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1 the proposed action (license renewal of Byron), new nuclear alternative, or the combination 

2 alternative. Air emissions from purchased power will vary and depend on the type of technology 

3 and whether the purchased power is from existing or new constructed technology. If purchased 

4 power is solely from coal-fired plants, air emissions would be higher as opposed to purchased 

5 power from nuclear plants, which would result in lower emissions. It is assumed that purchased 

6 power would come from a combination of technologies. In 2012, coal, natural gas, and nuclear 

7 power accounted for 37-, 30-, and 19-percent share, respectively, of total U.S. electricity 

8 generation (EIA 2014). Using these percent shares for the purchased power alternative, the 

9 NRC staff estimates that air emissions will be greater than the NGCC alternative, but less than 

10 the IGCC alternative. However, actual emissions may be greater or less than what is estimated 

11 in Table 4–3 and will depend on the technology from which the purchased power comes. 

12 Table 4–3. Estimated Direct Air Emissions From Operation of the Byron

13 Proposed Action and Alternatives (Tons/Year)

Proposed 

Action(a)

New 

Nuclear(b) IGCC NGCC Combination(c) Purchased Power (d)

NOx 28 28 3,000 600 80 1,295

SOx 0.02 0.02 820 380 50 417

PM10 23 23 480 210 30 188

CO 7.5 7.5 2,045 1,690 220 1,265

CO2e 1.5×103 1.5×103 14.3×106 7.9×106 1.0×106 7.7×106

(a) Highest annual emissions from the Byron Station during the 2008 to 2012 period.

(b) Assumed air emissions from the Byron Station.

(c) Assumed air emissions only from the NGCC portion of the combination alternative.

(d) Assumed air emissions were estimated by assuming that purchased power coal accounted for a 37% share, 

natural gas a 30% share, nuclear a 19% share, and renewable a 14% share of electricity generation.

Legend: CO = carbon monoxide; CO2e = carbon dioxide equivalent; PM10 = particulate matter, ≤10 μm; 

NOx = nitrogen oxides; SOx = sulfur oxides

14 Noise

15 As discussed in the sections above, noise levels and impacts from operation of the NGCC and 

16 new nuclear combination alternatives would not be greater than those associated with operation 

17 of the Byron site and expected to be SMALL. Noise levels and impacts from operation of the 

18 IGCC, combination, and purchased power are expected to be SMALL to MODERATE. Noise 

19 levels for these three alternatives are dependent on the distance of receptors to the noise 

20 sources unique to the technology. For instance, the IGCC alternative will introduce noise 

21 associated with rail delivery predicted to be in the 80 to 96 dBA range. The wind power portion 

22 of the combination alternative will introduce wind turbine noise levels that can reach 105 dBA.

23 4.4 Geologic Environment

24 This section describes the potential impacts of the proposed action (license renewal) and 

25 alternatives to the proposed action on geologic and soil resources.

26 During construction, for all the alternatives to the proposed action discussed in this section, 

27 sources of aggregate such as crushed stone and sand and gravel would be required to 

28 construct buildings, foundations, roads, and parking lots. These resources would likely be 
Environmental Consequences and Mitigating Actions

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1 obtained from commercial suppliers using local or regional sources. In addition, land would be 

2 cleared of vegetation. Land clearing during construction and the installation of power plant 

3 structures and impervious surfaces would expose soils to erosion and alter surface drainage. 

4 To reduce soil erosion, BMPs would be implemented in accordance with applicable permitting 

5 requirements. These practices would include use of sediment fencing, staked hay bales, check 

6 dams, sediment ponds, riprap aprons at construction and laydown yard entrances, mulching 

7 and geotextile matting of disturbed areas, and rapid reseeding of temporarily disturbed areas. 

8 Removed soils and any excavated materials would be stored on site for redistribution, such as 

9 for backfill at the end of construction. Therefore, for all the alternatives to the proposed action, 

10 construction impacts on geologic and soil resources would be SMALL.

11 Table 4–4 identifies issues related to geology and soils that are applicable to the Byron Station 

12 during the renewal term. Section 3.4 describes the local and regional geologic environment of 

13 the Byron site. 

14 Table 4–4. Geology and Soils Issues

Issue GEIS Section Category

Geology and soils 4.4.1 1

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51

15 4.4.1 Proposed Action

16 As further discussed below, the impact by the proposed action on geology and soil resources 

17 are SMALL.

18 The NRC staff did not identify any new and significant information associated with the 

19 Category 1 geology and soils issues identified in Table 4–4 during the review of the applicant’s 

20 ER (Exelon 2013a), the site audit, the scoping process, or the evaluation of other available 

21 information. As a result, no information or impacts related to these issues were identified that 

22 would change the conclusions presented in the GEIS (NRC 1996, 2013a). For these geology 

23 and soils issues, the GEIS concludes that the impacts are SMALL. Therefore, it is expected 

24 that there would be no incremental impacts related to these Category 1 issues during the 

25 renewal term beyond those discussed in the GEIS, and therefore the impacts associated with 

26 these issues by the proposed action would be SMALL.

27 4.4.2 No-Action Alternative

28 There would not be any impacts to the geology and soils at the Byron site with shutdown of the 

29 facility. Therefore, impacts would be SMALL.

30 4.4.3 New Nuclear Alternative

31 This alternative would be located at an existing plant site or retired coal plant site. As such, it 

32 would be located in an area where the soils had already been disturbed by previous activities at 

33 the site. For this alternative, the impacts on the geology and soil resources would occur during 

34 construction. As discussed in Section 4.4 of the GEIS (NRC 2013a), construction impacts for all 

35 alternatives to the proposed actions would be SMALL, and therefore the impact of this 

36 alternative on geology and soil resources would be SMALL.
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1 4.4.4 IGCC Alternative

2 This alternative would be located at an existing plant site. As such, it would be located in an 

3 area where the soils had already been disturbed by previous activities at the site. For this 

4 alternative, the impacts on the geology and soil resources would occur during construction. As 

5 discussed in Section 4.4 of the GEIS (NRC 2013a), construction impacts for all alternatives to 

6 the proposed actions would be SMALL, and therefore the impact of this alternative on geology 

7 and soil resources would be SMALL.

8 4.4.5 NGCC Alternative

9 This alternative would be located at an existing plant site or retired coal plant site. As such, it 

10 would be located in an area where the soils had already been disturbed by previous activities at 

11 the site. For this alternative, the impacts on the geology and soil resources would occur during 

12 construction. As discussed in Section 4.4 of the GEIS (NRC 2013a), construction impacts for all 

13 alternatives to the proposed actions would be SMALL, and therefore the impact of this 

14 alternative on geology and soil resources would be SMALL.

15 4.4.6 Combination Alternative (NGCC, Wind, Solar)

16 This alternative requires a large amount of land (up to 19,790 ac (8,009 ha)). However, much of 

17 the land would be undisturbed. For this alternative, the impacts on the geology and soil 

18 resources would occur during construction. As discussed in Section 4.4 of the GEIS

19 (NRC 2013a), construction impacts for all alternatives to the proposed actions would be SMALL,

20 and therefore the impact of this alternative on geology and soil resources would be SMALL.

21 4.4.7 Purchased Power

22 The impacts of this alternative on the geology and soil resources are likely to be bounded by the 

23 impact descriptions of the other alternatives, and therefore the impact of this alternative on 

24 geology and soil resources would be SMALL.

25 4.5 Water Resources

26 This section describes the potential impacts of the proposed action (license renewal) and 

27 alternatives to the proposed action on surface water and groundwater resources.

28 4.5.1 Proposed Action

29 4.5.1.1 Surface Water Resources

30 The Category 1 (generic) and Category 2 surface water use and quality issues applicable to 

31 Byron are discussed in the following sections and listed in Table 4–5. Surface water 

32 resource-related aspects and conditions relevant to the Byron site are described in 

33 Section 3.5.1.
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1 Table 4–5. Surface Water Resources Issues

Issue GEIS Section Category

Surface water use and quality (non-cooling system impacts) 4.5.1.1 1

Altered current patters at intake and discharge structures 4.5.1.1 1

Scouring caused by discharged cooling water 4.5.1.1 1

Discharge of metals in cooling system effluents 4.5.1.1 1

Discharge of biocides, sanitary wastes, and minor chemical spills 4.5.1.1 1

Surface water use conflicts (plants with cooling ponds or cooling towers

using makeup water from a river) 4.5.1.1 2 

Effects of dredging on surface water quality 4.5.1.1 1

Temperature effects on sediment transport capacity 4.5.1.1 1

Sources: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51; NRC 2013a

2 Generic Surface Water Resources

3 The NRC staff did not identify any new and significant information associated with the 

4 Category 1 surface water issues identified in Table 4–5 during the review of the applicant’s ER 

5 (Exelon 2013a), the site audit, the scoping process, or the evaluation of other available 

6 information. As a result, no information or impacts related to these issues were identified that 

7 would change the conclusions presented in the GEIS (NRC 2013a). For these issues the GEIS 

8 concludes that the impacts are SMALL. Therefore, it is expected that there would be no 

9 incremental impacts related to these Category 1 issues during the renewal term beyond those 

10 discussed in the GEIS, and therefore the impacts associated with these issues by the proposed 

11 action would be SMALL. 

12 The Category 2 (Table 4–5) issue related to surface water during the renewal term is discussed 

13 in the following text.

14 Surface Water Use Conflicts

15 This section presents the NRC staff’s review of the plant-specific (Category 2) surface water use 

16 conflict issue listed in Table 4–5.

17 Plants with Cooling Ponds or Cooling Towers Using Makeup Water From a River

18 For nuclear power plants using cooling towers or cooling ponds supplied with makeup water 

19 from a river, the potential impact on the flow of the river and its availability to meet the demands 

20 of other users is a Category 2 issue. This designation requires a plant-specific assessment. 

21 In evaluating the potential impacts resulting from surface water use conflicts associated with 

22 license renewal, the NRC staff uses as its baseline the surface water resource conditions as 

23 described in Sections 3.1.3 and 3.5.1. These baseline conditions encompass the defined 

24 hydrologic (flow) regime of the surface water(s) potentially affected by continued operations as 

25 well as the magnitude of surface water withdrawals for cooling and other purposes (as 

26 compared to relevant appropriation and permitting standards). The baseline also considers 

27 other downstream uses and users of surface water.

28 The mean annual discharge of the Rock River (see Section 3.5.1.1) measured at the 

29 U.S. Geological Survey (USGS) gage at Como, Illinois, is 6,033 cubic feet per second (cfs) 
Environmental Consequences and Mitigating Actions

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(170 cubic meters per second (m3 1 /s)). As described in Section 3.5.1.2, Byron’s average surface 

water withdrawal rate from the Rock River is 83.2 cfs (2.35 m3 2 /s or 53.8 mgd), with consumptive 

use averaging 52.9 cfs (1.5 m3 3 /s or 34.2 mgd). This results in a rate of consumption of 

4 0.9 percent of the Rock River’s average flow. Further, the lowest annual mean flow recorded 

for the Rock River at Como, Illinois, is 2,187 cfs (61.9 m3 5 /s), and the mean 

90 percent-exceedance flow is 1,760 cfs (49.7 m3 6 /s) for the period of record. Compared to 

7 these measures of reduced river flow, Byron’s consumptive water use represents a 2.4- and a 

8 3.0-percent reduction, respectively, in the flow of the Rock River downstream of Byron Station.

9 In addition, the provisions of Exelon’s agreement with the State pursuant to Byron’s construction 

10 permit for its cooling water intake limit the plant’s consumptive use of surface water to no more 

than 9 percent of total river flow when river flow is at or below 679 cfs (19.1 m3 11 /s). This 

condition would represent a consumptive use totaling about 61 cfs (1.7 m3 12 /s) for Byron 

13 operations (see Section 3.5.1.2). Under low river flow conditions, a plant operating procedure 

14 stipulates actions that Exelon personnel must take to maintain compliance including reducing 

15 circulating water makeup and blowdown flows and, if necessary, reducing reactor power output 

16 to reduce consumptive water use.

17 The construction permit also limits Byron’s maximum makeup withdrawal rate from the river to 

125 cfs (3.5 m3 18 /s). However, the maximum (nominal) surface water withdrawal rate for Byron is 

about 101 cfs (2.85 m3 19 /s), and, as a result, the maximum permitted withdrawal rate would not 

20 likely be exceeded during the period of continued operations.

21 Future Rock River flow is not expected to significantly change over the license renewal period 

22 (Dziegielewski et al. 2005; Exelon 2013a). Future water demand (both groundwater and 

23 surface water) in the Illinois counties within the Rock River basin is projected to increase by 

24 about 10 percent from 2000 to 2025. Most of this projected demand is for thermoelectric 

25 generation near the southern end of the river in the County of Rock Island (Dziegielewski 

26 et al. 2005; IEPA 2006).

27 In conclusion, operation of Byron during the license renewal term is not expected to result in a 

28 water use conflict on the Rock River. Byron’s surface water withdrawals and low rate of 

29 consumptive use of Rock River flow is very unlikely to impact the downstream availability and 

30 instream uses of surface water. Byron’s surface water withdrawals are also subject to low-flow 

31 limitations imposed by the State of Illinois. Therefore, the NRC staff concludes that the potential 

32 impacts on surface water resources and downstream water availability from Byron’s 

33 consumptive water use during the license renewal term would be SMALL. 

34 4.5.1.2 Groundwater Resources

35 Table 4–6 identifies issues related to groundwater that are applicable to Byron Station during 

36 the renewal term. Section 3.5.2 describes groundwater resources at the Byron Station.

37 The NRC staff did not identify any new and significant information associated with the 

38 Category 1 groundwater issues identified in Table 4–6 during the review of the applicant’s ER, 

39 the site audit, the scoping process, or the evaluation of other available information. As a result, 

40 no information or impacts related to these issues were identified that would change the 

41 conclusions presented in the GEIS (NRC 2013a). For these issues, the GEIS concludes that 

42 the impacts are SMALL. Therefore, it is expected that there would be no incremental impacts 

43 related to these Category 1 issues during the renewal term beyond those discussed in the 

44 GEIS, and therefore the impacts associated with these issues by the proposed action would be 

45 SMALL. 
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1 Table 4–6. Groundwater Issues

Issue GEIS Section Category

Groundwater contamination and use (noncooling system 

impacts) 4.5.1.2 1 

Groundwater use conflicts (plants that withdraw less than 

100 gpm) 4.5.1.2 1 

Groundwater use conflicts (plants with closed-cycle cooling 

systems that withdraw makeup water from a river) 4.5.1.2 2 

Radionuclides released to groundwater 4.5.1.2 2

Source: Table B-1 in Appendix B, Subpart A to 10 CFR Part 51

2 The Category 2 issues related to groundwater during the renewal term are discussed in the 

3 following text (see also Table 4–6).

4 Groundwater Use Conflicts (Plants Using Cooling Towers or Cooling Ponds and Withdrawing 

5 Makeup Water From a Small River)

6 The issue of groundwater use conflicts applies to the Byron Station because it uses cooling 

7 towers and withdraws water from a small river. Cooling towers lose water to the atmosphere by 

8 evaporation and drift. As a result, less water is returned to Rock River than is withdrawn. This 

9 issue evaluates the impact of consuming river water and its impact on groundwater supplies.

10 The Rock River Alluvium is hydrologically connected to both the Galena-Platteville Dolomite 

11 Aquifer and the St. Peter Sandstone Aquifer. Groundwater from these aquifers discharges into 

12 the river alluvium. As described in Section 4.5.1.1, the low impact of plant water consumption 

13 on Rock River flows over the period of licensing, and therefore on river water levels, means that 

14 local aquifers in the site area are very unlikely to suffer dewatering from the consumptive use of 

15 river water by the Byron plant. Therefore, the NRC staff concludes that impacts to groundwater

16 use would be SMALL.

17 Radionuclides Released to Groundwater

18 As described in Section 3.5.2.3, Exelon discovered in 2006 that water had leaked from some of 

19 the vacuum breaker vaults located along the blowdown pipeline running from the plant to the 

20 Rock River. The leaked water contaminated a small area of the Galena-Platteville Dolomite 

21 aquifer near a few vacuum breaker vaults with low levels of tritium. Other than tritium, no 

22 radionuclides above their lower limit of laboratory detection were or have since been discovered 

23 from these leaks. Tritium concentrations in the area of contamination were and are well below 

24 the EPA drinking water standard of 20,000 picocuries per liter. Exelon has improved monitoring 

25 along the pipeline and taken additional measures to prevent future groundwater contamination 

26 from the discharge pipeline.

27 Probably as a result of dilution from local recharge to the aquifer and from dispersion, from 2007 

28 to 2013, tritium concentrations in the areas of groundwater contamination have steadily 

29 decreased. There are no wells between the area of contamination and the river (in the direction 

30 of groundwater flow); therefore, it is not anticipated that tritium-contaminated groundwater would 

31 be intercepted by a private well user. Any tritium in the groundwater that reached the Rock 

32 River would be greatly reduced in concentration by the relatively large volumes of water flowing 

33 in the river.
Environmental Consequences and Mitigating Actions

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1 Remediation of the contaminated groundwater at Byron Station is not planned by Exelon, 

2 because of its low tritium concentrations, limited extent of the contamination, and because the 

3 problems causing the leaks from the vacuum breakers along the pipeline have been corrected. 

4 The NRC staff will continue to monitor any unanticipated radionuclide releases and take 

5 appropriate regulatory action, as warranted. Final cleanup of the site, including contaminated 

6 geologic materials, would be addressed by Exelon with NRC oversight during decommissioning 

7 of the facility.

8 Based on its review, the NRC staff concludes that inadvertent releases of tritium have not 

9 substantially impaired site groundwater quality and future groundwater quality impacts are not 

10 anticipated. The NRC staff therefore concludes that groundwater quality impacts from 

11 “radionuclides released to groundwater” are SMALL.

12 4.5.2 No-Action Alternative

13 4.5.2.1 Surface Water Resources

14 The rate of consumptive use of surface water would greatly decrease and eventually cease after 

15 Byron is shut down. Wastewater discharges would be reduced considerably. Shutdown would 

16 reduce the impacts on surface water use and quality. Therefore, the impact of this alternative 

17 on surface water resources would be SMALL.

18 4.5.2.2 Groundwater Resources

19 With the cessation of operations at the Byron site, the consumption of groundwater would be 

20 much less and there should be little or no impacts on groundwater quality. Therefore, the 

21 impact of this alternative on groundwater resources would be SMALL.

22 4.5.3 New Nuclear Alternative

23 4.5.3.1 Surface Water Resources

24 Impacts from construction activities on surface water resources associated with the new nuclear 

25 alternative would be considerable in scale by virtue of the land area required for new nuclear 

26 units (i.e., 355 ac (143 ha)). Deep excavation work for the nuclear island as well as extensive 

27 site clearing and a large laydown area for facility construction would have the potential for direct 

28 and indirect impacts on water resources.

29 Construction activities would alter any onsite surface water drainage features. Some temporary 

30 impacts to surface water quality may result from increased sediment loading and from any 

31 pollutants in stormwater runoff from disturbed areas, from excavation, and any dredge-and-fill 

32 activities. Stormwater runoff from construction areas and spills and leaks from construction 

33 equipment could potentially affect downstream surface water quality. Nevertheless, application 

34 of BMPs in accordance with a State-issued National Pollutant Discharge Elimination System

35 (NPDES) general permit, including appropriate waste management, water discharge, 

36 stormwater pollution prevention, and spill prevention practices, would prevent or minimize any 

37 surface water quality or groundwater quality impacts during construction.

38 In addition, the NRC staff assumes that any existing intake and discharge infrastructure at an 

39 alternative site location would be refurbished and used to maximize use of existing facilities. 

40 This would reduce construction-related impacts on surface water quality. Dredge-and-fill 

41 operations would be conducted under a permit from the U.S. Army Corps of Engineers 

42 (USACE) and State-equivalent permits requiring the implementation of applicable BMPs to 

43 minimize associated impacts.
Environmental Consequences and Mitigating Actions

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1 The staff assumes that there would be no direct use of surface water during construction 

2 because it is expected that groundwater would be used or water could be supplied by a local 

3 water utility or trucked to the point of use. During construction, the dewatering of excavations 

4 would not be expected to affect offsite surface water bodies.

The operation of the two new nuclear units would require an estimated 83.5 cfs (2.4 m3 5 /s or 

6 54 million gallons per day (mgd)) of surface water for cooling makeup and related processes. 

Consumptive water use would be approximately 62 cfs (1.75 m3 7 /s or 40 mgd), equivalent to 

8 approximately 1.0 percent of the Rock River’s average flow. The projected consumptive use

9 under this alternative represents about 17 percent more surface water than current Byron 

operations, which consume approximately 52.9 cfs (1.5 m3 10 /s or 34.2 mgd) (see Sections 3.5.1.2 

11 and 4.5.1.1). However, the NRC staff expects that that State would impose limits on surface 

12 water withdrawals and consumption during low river flows, similar to those currently in place for 

13 Byron, which would reduce the cited makeup water and consumptive use demands for this 

14 alternative on an annualized basis. 

15 The NRC staff further expects that water treatment additives for new nuclear plant operations 

16 and effluent discharges would be relatively similar in quality and volume to Byron. Additionally, 

17 effluent discharges and storm water discharges would be subject to a State-issued NPDES

18 permit, and surface water withdrawals would be subject to applicable state water appropriation 

19 and registration requirements. To prevent and respond to accidental nonnuclear releases to 

20 surface water, facility operations would be conducted in accordance with a spill prevention, 

21 control, and countermeasures plan; storm water pollution prevention plan; or equivalent plans 

22 and associated BMPs and procedures.

23 Based on the above, the overall impacts on surface water use and quality from construction and 

24 operations under the new nuclear alternative would be SMALL to MODERATE.

25 4.5.3.2 Groundwater Resources

26 For this alternative, as discussed in Section 4.5 of the GEIS, construction impacts for all 

27 alternatives to the proposed action on groundwater resources would be SMALL. Also as

28 discussed in Section 4.5 of the GEIS, operational impacts for all alternatives to the proposed 

29 action on groundwater quality would be SMALL. During operations the consumptive use of 

30 groundwater would be similar to the proposed action. Therefore, the impacts of this alternative 

31 on groundwater resources would be SMALL.

32 4.5.4 IGCC Alternative

33 4.5.4.1 Surface Water Resources

34 Impacts from construction activities associated with the IGCC alternative on surface water

35 resources would be expected to be similar to but somewhat greater than those under the new 

36 nuclear alternative (see Section 4.5.3.1). The potential for greater impacts is attributable to the 

37 additional land required for construction of the power blocks for four IGCC units and for 

38 excavation and construction of other onsite facilities for coal handling and storage, and for coal 

39 ash and scrubber waste management. The same assumptions for construction and operations 

40 also apply to this alternative, except as noted.

41 Some temporary impacts to surface water quality may result from increased sediment loading 

42 and from pollutants in stormwater runoff from disturbed areas and from excavation and 

43 dredge-and-fill activities. There also would be the potential for hydrologic and water-quality 

44 impacts to occur from the extension or refurbishment of rail spurs to transport coal and other 

45 materials to, and coal ash from, potential site locations. Use of the Byron site would have the 

46 advantage of use of the existing cooling water intake, effluent discharge, and rail infrastructure. 
Environmental Consequences and Mitigating Actions

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1 Regardless, as described in Section 4.5.3.1 for the new nuclear alternative, water-quality 

2 impacts would be minimized by the application of BMPs and compliance with State-issued 

3 NPDES permits for construction. Any dredge-and-fill operations would be conducted under a 

4 permit from the USACE and State-equivalent permits requiring the implementation of BMPs to 

5 minimize impacts.

6 Operation of an IGCC plant would require less makeup water and would have lower 

7 consumptive use than either the new nuclear alternative or current Byron operations. The 

8 projected cooling water makeup requirement for an IGCC plant under this alternative is 51 cfs

(1.44 m3

/s or 33 mgd), with consumptive use of about 40 cfs (1.14 m3 9 /s or 26 mgd). This 

10 alternative would consume about 24 percent less surface water than current Byron operations, 

which consumes approximately 52.9 cfs (1.5 m3 11 /s or 34.2 mgd).

12 As summarized in Section 4.5.3.1 for the new nuclear alternative, surface water withdrawals 

13 and effluent discharges would be subject to applicable regulatory requirements under this 

14 alternative. However, management of runoff and leachate from coal and ash storage facilities 

15 would require additional regulatory oversight and would present an additional risk to surface 

16 water resources in proximity to site locations.

17 For this alternative, based on the projected magnitude of ground disturbance and hydrologic 

18 alteration and potential water quality impacts from coal and ash handling and management, 

19 impacts on surface water resources would range from SMALL to MODERATE.

20 4.5.4.2 Groundwater Resources

21 For this alternative, as discussed in Section 4.5 of the GEIS, construction impacts for all 

22 alternatives to the proposed action on groundwater resources would be SMALL. Also as 

23 discussed in Section 4.5 of the GEIS, operational impacts for all alternatives to the proposed 

24 action on groundwater quality would be SMALL. During operations the consumptive use of 

25 groundwater would be similar to the proposed action. Therefore, the impacts of this alternative 

26 on groundwater resources would be SMALL.

27 4.5.5 NGCC Alternative

28 4.5.5.1 Surface Water Resources

29 Direct impacts from construction activities associated with the NGCC alternative on surface 

30 water resources would be expected to be much smaller than those under either the new nuclear

31 or IGCC alternative. A new NGCC plant and associated pipelines would occupy a much smaller 

32 footprint (i.e., about 94 ac (38 ha)) than the current Byron plant or the proposed new nuclear or 

33 IGCC facilities. This would result in less extensive excavation and earthwork. Otherwise, the 

34 same assumptions for construction and operations also apply to this alternative, except as 

35 noted. In particular, use of the Byron site would offer the advantage of use of the existing 

36 cooling water intake and discharge infrastructure.

37 Some temporary impacts to surface water quality may result from increased sediment loading 

38 and from any pollutants in stormwater runoff from disturbed areas, from excavation, and 

39 dredge-and-fill activities. Depending on the path of any required new gas pipelines and 

40 transmission lines to service the NGCC plant, some stream crossings could be necessary. 

41 However, because of the short-term nature of any required dredging and filling and 

42 stream-crossing activities, the hydrologic alterations and sedimentation would be localized and 

43 water-quality impacts would be temporary and would cease after construction has been 

44 completed and the site stabilized. The use of modern pipeline construction techniques, such as 

45 horizontal directional drilling, would further minimize the potential for water-quality impacts in the 

46 affected streams. In addition, as described in Section 4.5.3.1 for the new nuclear alternative, 
Environmental Consequences and Mitigating Actions

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1 water-quality impacts would be minimized by the application of BMPs and compliance with 

2 State-issued NPDES permits for construction. Any dredge-and-fill operations would be 

3 conducted under a permit from the USACE and State-equivalent permits requiring the 

4 implementation of BMPs to minimize impacts.

5 For onsite facility operations, a five-unit NGCC plant would have a smaller cooling water 

6 demand and lower consumptive water use as compared to current Byron operations and the 

7 new nuclear and IGCC alternatives. It is projected that an NGCC plant would require 

approximately 26.3 cfs (0.74 m3 8 /s or 17 mgd) of surface water for cooling and related 

processes, with consumptive use totaling about 20.1 cfs (0.57 m3 9 /s or 13 mgd). Thus, this 

10 alternative would consume about 62 percent less surface water than current Byron operations, 

which consumes approximately 52.9 cfs (1.5 m3 11 /s or 34.2 mgd).

12 Based on this analysis, the overall impacts on surface water resources from construction and 

13 operations under the NGCC alternative would be SMALL.

14 4.5.5.2 Groundwater Resources

15 For this alternative, as discussed in Section 4.5 of the GEIS , construction impacts for all 

16 alternatives to the proposed action on groundwater resources would be SMALL. Also as 

17 discussed in Section 4.5 of the GEIS, operational impacts for all alternatives to the proposed 

18 action on groundwater quality would be SMALL. During operations the consumptive use of 

19 groundwater would be similar to the proposed action. Therefore, the impacts of this alternative 

20 on groundwater resources would be SMALL.

21 4.5.6 Combination Alternative (NGCC, Wind, Solar)

22 4.5.6.1 Surface Water Resources

23 For the NGCC component of this alternative, the impacts on surface water resources from 

24 facility construction and operations at either the Byron site or alternative sites would be a 

25 fraction of those described in Section 4.5.5.1 because the NGCC plant would be scaled back to 

26 a single 360-MW unit. As a result, operational cooling water demands would be reduced by 

27 about 85 percent.

28 Impacts on surface water resources from constructing up to 2,532 land-based wind turbines 

29 would primarily be limited to the relatively small amounts of water needed at each installation 

30 site for dust suppression and soil compaction during site clearing and for concrete production. 

31 Construction of utility-scale solar PV farms would require relatively large volumes of water per 

32 site due to the much larger land area required per MW of replacement power produced. For 

33 both components under this alternative, the NRC assumes that required water would be 

34 procured from offsite sources and trucked to the point of use on an as-needed basis. Water 

35 could also be supplied via a local water utility. The likely use of ready-mix concrete would also 

36 reduce the need for onsite use of nearby water sources for construction.

37 Installation of land-based wind turbines and utility-scale solar PV farms would also require 

38 construction of access roads and possibly transmission lines (especially for sites not already 

39 proximal to transmission line corridors). Access road construction would also require some 

40 water for dust suppression and roadbed compaction and would have the potential to result in 

41 soil erosion and stormwater runoff from cleared areas. For construction, water would likely be 

42 trucked to the point of use from offsite locations along with road construction materials. In all 

43 cases, it is expected that construction activities would be conducted in accordance with 

44 State-issued NPDES or equivalent permits for stormwater discharges associated with 

45 construction activity, which would require the implementation of appropriate BMPs to prevent or 

46 mitigate water-quality impacts. In contrast to land-based wind turbine sites and utility-scale 
Environmental Consequences and Mitigating Actions

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1 solar PV farms, installation of small solar PV units on rooftops and at already-developed sites 

2 within the electric service ROI (see Section 2.2.2) would have little or no impact on surface 

3 water resources.

4 To support the operation of wind turbine and PV installations, no direct use of surface water

5 would be expected. Water would likely be obtained from groundwater or purchased from a 

6 water utility. Regardless, only very small amounts of water would be needed to periodically 

7 clean turbine blades and motors and could be trucked to the point of use as part of routine 

8 servicing. Water also would be required to clean panels at solar PV farms or situated in rooftop 

9 arrays. Adherence to appropriate waste management and minimization plans, spill prevention 

10 practices, and pollution prevention plans during servicing of wind turbine and solar PV 

11 installations and operation of vehicles connected with site operations would minimize the risks 

12 to soils and surface water resources from spills of petroleum, oil, and lubricant products and 

13 stormwater runoff. 

14 In consideration of these facts, the impacts on surface water resources from construction and 

15 operations under the combination alternative would be SMALL.

16 4.5.6.2 Groundwater Resources

17 For this alternative, as discussed in Section 4.5 of the GEIS , construction impacts for all 

18 alternatives to the proposed action on groundwater resources would be SMALL. Also as 

19 discussed in Section 4.5 of the GEIS, operational impacts for all alternatives to the proposed 

20 action on groundwater quality would be SMALL. During operations the consumptive use of 

21 groundwater would be much smaller than the proposed action. Therefore, the impacts of this 

22 alternative on groundwater resources would be SMALL.

23 4.5.7 Purchased Power

24 4.5.7.1 Surface Water Resources

25 The impacts of this alternative on surface water resources are likely to be bounded by the 

26 impact descriptions for the other alternatives, except that no new construction would be likely. 

27 Specifically, new and continued operation of nuclear, coal-fired, and natural gas-fired plants and 

28 renewable energy projects would not be expected to result in incremental impacts on surface 

29 water use and quality that are greater than those described in Sections 4.5.3, 4.5.4, 4.5.5, and 

30 4.5.6 provided that all energy-generating facilities operate within their associated water use and 

31 NPDES permits. Therefore, the impact of this alternative on surface water resources would be 

32 expected to range from SMALL to MODERATE.

33 4.5.7.2 Groundwater Resources

34 The impacts of this alternative on groundwater resources are likely to be bounded by the impact 

35 descriptions for the other alternatives. Therefore, the impact of this alternative on groundwater

36 resources would be SMALL.

37 4.6 Terrestrial Resources

38 This section describes the potential impacts of the proposed action (license renewal) and 

39 alternatives to the proposed action on terrestrial resources.

40 4.6.1 Proposed Action

41 Section 3.6 of this SEIS describes terrestrial resources on and in the vicinity of the Byron site. 

42 The generic (Category 1) and site-specific (Category 2) issues that apply to terrestrial resources 
Environmental Consequences and Mitigating Actions

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1 during the proposed license renewal period appear in Table 4–7. The GEIS (NRC 2013a) 

2 discusses these issues in Section 4.6.1.1.

3 Table 4–7. Terrestrial Resource Issues

Issue GEIS Section Category

Effects on terrestrial resources (noncooling system impacts) 4.6.1.1 2

Exposure of terrestrial organisms to radionuclides 4.6.1.1 1

Cooling tower impacts on vegetation (plants with cooling towers) 4.6.1.1 1

Bird collisions with plant structures and transmission lines (a) 4.6.1.1 1

Water use conflicts with terrestrial resources (plants with cooling ponds 

or cooling towers using makeup water from a river) 4.6.1.1 2 

Transmission line ROW management impacts on terrestrial resources (a) 4.6.1.1 1

Electromagnetic fields on flora and fauna (plants, agricultural crops, 

honeybees, wildlife, livestock)(a) 4.6.1.1 1 

(a) This issue applies only to the inscope portion of electric power transmission lines, which are defined as 

transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional 

power distribution system and transmission lines that supply power to the nuclear plant from the grid.

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51

4 4.6.1.1 Generic Terrestrial Resource Issues

5 For the generic (Category 1) terrestrial resources issues listed in Table 4–7, the NRC staff did 

6 not identify any new and significant information related to the generic (Category 1) issues listed 

7 above during the review of the applicant’s ER (Exelon 2013a), the site audit, or the scoping

8 process. Therefore, the NRC staff expects no impacts associated with these issues beyond 

9 those discussed in the GEIS. The GEIS concludes that the impact level for each of these 

10 issues is SMALL.

11 4.6.1.2 Effects on Terrestrial Resources (Noncooling System Impacts)

12 In the GEIS (NRC 2013a), the NRC staff determined that noncooling system effects on 

13 terrestrial resources is a Category 2 issue (see Table 4–7) that requires site-specific evaluation 

14 during each license renewal review. According to the GEIS, noncooling system impacts can 

15 include those impacts that result from landscape maintenance activities, stormwater

16 management, elevated noise levels, and other ongoing operations and maintenance activities 

17 that would occur during the renewal period and that could affect terrestrial resources on and 

18 near the Byron site.

19 Section 3.6 indicates that approximately 1,244 ac (503 ha) of the Byron site (70 percent) 

20 remains as natural areas that are either leased for agricultural use or as unmanaged forest, 

21 meadow, or grassland habitat (Exelon 2014). The majority of site landscape maintenance is 

22 performed within the protected area and not within natural areas on the site. Typically, only 

23 trees and shrubs that pose a safety or security threat are removed from natural areas. Leased 

24 lands are maintained by the leasee in accordance with the standing lease.

25 Stormwater on the Byron site drains into the Construction Runoff Pond. From the pond, water 

26 either flows into the Unit 2 natural draft cooling tower basin where it becomes part of the 

27 circulating water system, or it flows through NPDES Outfall 003 via drainage ditches located 
Environmental Consequences and Mitigating Actions

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1 along German Church Road to the north of the main plant complex (Exelon 2013a). Special 

2 Condition 16 of the NPDES permit requires Exelon to develop and implement a Stormwater 

3 Pollution Prevention Plan (Exelon 2013a). This plan identifies sources of pollution that could 

4 affect the quality of stormwater and describes practices that Exelon uses to reduce such 

5 pollutants. Areas with spill potential, such as areas around tanks that contain oil, are further 

6 monitored under the Byron Station Spill Prevention Control and Countermeasure Plan. 

7 Collectively, these measures ensure that the effects to terrestrial resources from pollutants 

8 carried by stormwater would be small during the proposed license renewal term.

9 The GEIS (NRC 2013a) indicates that elevated noise levels could be a noncooling system 

10 impact to terrestrial resources. However, the GEIS also concludes that generic noise impacts

11 would be small because noise levels would remain well below regulatory guidelines for offsite 

12 receptors during continued operations and refurbishment associated with license renewal. The 

13 NRC staff did not identify any information during its review that would indicate that noise 

14 impacts to terrestrial resources at Byron would be unique or require separate analysis.

15 Other operations and maintenance activities that could occur in the future include the 

16 replacement of the Unit 2 steam generators (SGs). While Exelon has previously replaced the 

17 Unit 1 SGs, Exelon has not replaced the Unit 2 SGs. Exelon has no plans to replace the Unit 2 

18 SGs at this time, but may choose to replace them prior to the end of the 40-year initial license 

19 term. Because SG replacement is not necessary for safe operation during license renewal, the 

20 NRC does not consider it part of the proposed action. As such, the impacts of Unit 2 SG 

21 replacement on terrestrial resources are discussed in Section 4.16.4 rather than in this section. 

22 Exelon (2013a) is planning no other land-disturbing activities or construction unrelated to 

23 possible Unit 2 SG replacement. No disturbances to natural habitats would occur during license 

24 renewal, and Exelon does not expect any changes in operations or changes to existing land 

25 uses during the proposed license renewal period. As such, no measurable impacts to the 

26 terrestrial environment are expected during the license renewal period. 

27 When new activities that could impact the environment occur at Byron, Exelon follows several 

28 procedures to ensure that potential environmental effects are considered and appropriately 

29 addressed. Exelon maintains a procedure (No. EN-AA-103) that requires Exelon staff to screen 

30 proposed activities, such as maintenance activities, operational changes, procedure changes, 

31 and other facility activities, to determine if the activity warrants further evaluation for 

32 environmental impact or risk (Exelon 2013b). If the activity warrants further evaluation, Exelon 

33 Procedure No. EN-AA-103-F-02 provides guidance to Exelon staff on performing such an 

34 evaluation and determining the environmental and regulatory impacts of the activity 

35 (Exelon 2013b). This procedure also requires that implementation of the activity be halted until 

36 any environmental impacts are addressed.

37 Based on the NRC staff’s independent review, the staff concludes that the landscape 

38 maintenance activities, stormwater management, elevated noise levels, and other ongoing 

39 operations and maintenance activities that Exelon might undertake during the renewal term 

40 would primarily be confined to disturbed areas of the Byron site. These activities would not 

41 have noticeable effects on terrestrial resources, nor would they destabilize any important 

42 attribute of the terrestrial resources on or in the vicinity of the Byron site. Therefore, the NRC 

43 staff expects noncooling system impacts on terrestrial resources during the license renewal 

44 term to be SMALL.

45 4.6.1.3 Water Use Conflicts with Terrestrial Resources (Plants with Cooling Ponds or Cooling 

46 Towers Using Makeup Water from a River)

47 In the GEIS (NRC 2013a), the NRC staff determined that effects of water use conflicts on 

48 terrestrial resources is a Category 2 issue (see Table 4–7) that requires site-specific evaluation 
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1 during each license renewal review. Water use conflicts occur when the amount of water 

2 needed to support terrestrial resources is diminished as a result of demand for agricultural, 

3 municipal, or industrial use or decreased water availability due to droughts, or a combination of 

4 these factors.

5 Section 4.5.1.1 addresses surface water use conflicts and concludes that the potential impacts 

6 on surface water resources and downstream water availability from Byron’s consumptive water 

7 use during the license renewal term would be SMALL because the State of Illinois imposes 

8 withdrawal restrictions to ensure adequate instream and downstream flows. Section 4.7.1.2 

9 addresses water use conflicts with aquatic resources and determines that Byron has consumed 

10 a very small amount (between 0.7 and 1.7 percent) of the Rock River’s flow each year for the 

11 past 12 years, under the conservative assumption that Byron was operating at 100 percent

12 power at all times. This section concludes that the impacts of water use conflicts would be 

13 SMALL for terrestrial resources. The NRC staff finds no other impacts that would be 

14 experienced by riparian or other terrestrial habitats that are not discussed in Sections 4.5.1.1 or 

15 4.7.1.2. Accordingly, the NRC staff concludes that the impact of water use conflicts on 

16 terrestrial resources from the proposed license renewal would be SMALL. 

17 4.6.2 No-Action Alternative

18 If Byron were to shut down, the impacts to terrestrial ecology would remain similar to those 

19 during operations until the plant is fully decommissioned. Temporary buildings and staging or 

20 laydown areas may be required during large component and structure dismantling. Byron is 

21 likely to have sufficient space within previously disturbed areas for these needs, and therefore, 

22 no additional land disturbances would occur on previously undisturbed land. Adjacent lands 

23 may experience temporary increases in erosional runoff, dust, or noise, but these impacts could 

24 be minimized with the implementation of standard BMPs (NRC 2002). In NUREG–0586, 

25 Generic Environmental Impact Statement on Decommissioning of Nuclear Facilities, 

26 Supplement 1, NRC (2002) concludes generically that impacts to terrestrial ecology during 

27 decommissioning activities would be SMALL. Reclamation of the site following 

28 decommissioning could create terrestrial habitat in areas currently used as industrial areas. The 

29 GEIS (NRC 2013a) notes that terrestrial resource impacts could occur in other areas beyond 

30 the immediate nuclear plant site as a result of the no-action alternative if new power plants are 

31 needed to replace lost capacity. The NRC staff concludes that the no-action alternative is 

32 unlikely to noticeably alter or have more than minor effects on terrestrial resources. Thus, the 

33 NRC staff concludes that the impacts of the no-action alternative on terrestrial resources during 

34 the proposed license renewal term would be SMALL.

35 4.6.3 New Nuclear Alternative

36 The new nuclear alternative assumes that the new facility would be built at an existing nuclear 

37 or retired coal plant site within the ROI but outside of Illinois. Construction of the new nuclear 

38 plant would require an estimated 324 ac (131 ha) for permanent buildings and facilities and an 

39 additional 31 ac (12.5 ha) for temporary facilities and laydown areas. The NRC staff assumes 

40 that this alternative would use existing onsite structures and previously disturbed areas to the 

41 extent practicable to minimize new development in undisturbed areas. However, given the land 

42 requirements, it is expected that some undisturbed areas would be affected, which would 

43 directly impact terrestrial resources. During construction, terrestrial species could experience 

44 habitat loss or fragmentation, loss of food resources, and altered behavior due to noise and 

45 other construction-related disturbances. Erosion and sedimentation from clearing, leveling, and 

46 excavating land could affect adjacent riparian and wetland habitats, if present. Implementation 

47 of appropriate BMPs would minimize these effects. This alternative could also require 
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1 construction of new transmission lines or upgrades to existing lines. Because the new nuclear 

2 facility would be located on an existing energy-producing site, transmission lines could likely be 

3 colocated within existing transmission line corridors to minimize land disturbance. Although 

4 construction activities could noticeably alter terrestrial resources through habitat loss or 

5 fragmentation, construction is unlikely to destabilize any important attributes of the terrestrial 

6 environment. The exact magnitude of impacts would vary based on the chosen location of the 

7 facility and the amount and types of undisturbed habitat that would be affected by construction 

8 of the alternative, and thus, impacts of construction could range from SMALL to MODERATE.

9 During operation, impacts would be similar in type and magnitude to those assessed in 

10 Section 4.6.1 for continued operation of Byron under the proposed renewal term and would, 

11 therefore, be SMALL.

12 The NRC concludes that the impacts of construction and operation of the new nuclear 

13 alternative on terrestrial resources would be SMALL to MODERATE.

14 4.6.4 IGCC Alternative

15 The IGCC alternative assumes that the new facility would be built at an existing 

16 energy-producing site or a retired coal plant site in Illinois or another state within the ROI. The 

17 facility would require 2,000 ac (809 ha) of land to construct the facility. The NRC staff assumes 

18 that this alternative would use existing onsite structures and previously disturbed areas to the 

19 extent practicable to minimize new development in undisturbed areas. However, because the 

20 footprint of the facility would be large, it is likely that construction would require clearing of 

21 previously undisturbed terrestrial habitats. This would result in habitat loss and fragmentation 

22 and loss of food resources. Terrestrial species may also alter their behaviors due to noise and 

23 other construction-related disturbances. Erosion and sedimentation from clearing, leveling, and 

24 excavating land could affect adjacent riparian and wetland habitats, if present. Implementation 

25 of appropriate BMPs would minimize these effects. This alternative could also require 

26 construction of new transmission lines or upgrades to existing lines. Because the IGCC facility 

27 would be located on an existing energy-producing site, any new transmission lines could likely 

28 be colocated within existing transmission line corridors to minimize land disturbance. 

29 Depending on the site and terrestrial habitats present, construction activities could noticeably 

30 alter or destabilize attributes of the terrestrial environment due to the large land requirements of 

31 the facility. The exact magnitude of impacts would vary based on the chosen location of the 

32 facility and the amount and types of undisturbed habitat that would be affected by construction 

33 of the alternative. The NRC staff expects that impacts of construction on terrestrial resources 

34 would be MODERATE.

35 The GEIS (NRC 2013a) concludes that impacts to terrestrial resources from operation of fossil 

36 energy alternatives would essentially be similar to those from continued operations of a nuclear 

37 facility. Unique impacts would include periodic maintenance dredging if coal is delivered by 

38 barge, which could create noise, dust, and sedimentation. Dredging and delivery of coal to the 

39 site could introduce minerals and trace elements to water resources on which terrestrial biota

40 rely. Such minerals could also bioaccumulate in nearby riparian or wetland habitats. Air 

41 emissions during operation would include sulfur oxides and nitrogen oxides, which can combine 

42 with water vapor and create sulfuric and nitric acids. These acids would then be released back 

43 into the environment through precipitation, which could affect the acidity levels of water 

44 resources and have detrimental effects to plant foliage. Acid precipitation has the potential to 

45 destabilize the terrestrial environment by creating conditions that are too acidic for certain plants 

46 or animals. The IGCC facility would also emit various GHGs during operation, which is an effect 

47 that can have far-reaching consequences because GHGs contribute to climate change. The 

48 effects of climate change on terrestrial resources are discussed in Section 4.13.3.2. The 
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1 various air emissions during operation of the IGCC facility could create noticeable impacts that

2 could destabilize certain attributes of the terrestrial environment, and therefore, the operational 

3 impacts would be MODERATE.

4 The NRC concludes that the impacts of construction and operation of the IGCC alternative on 

5 terrestrial resources would be MODERATE.

6 4.6.5 NGCC Alternative

7 The NGCC alternative assumes that the facility would be built at an existing energy-producing 

8 site or a retired coal plant site in Illinois or another state within the ROI. The facility would 

9 require 94 ac (38 ha) of land for the plant and associated pipelines. Because the footprint of the 

10 facility would be relatively small, the entire construction footprint could likely be sited in already 

11 developed areas of the site, which would minimize impacts to terrestrial habitats and species. 

12 However, the level of direct impact would vary based on the specific location of new buildings 

13 and infrastructure on the site. During construction, terrestrial species could experience habitat 

14 loss or fragmentation, loss of food resources, and altered behavior due to noise and other 

15 construction-related disturbances. Erosion and sedimentation from clearing, leveling, and 

16 excavating land could affect adjacent riparian and wetland habitats, if present. Implementation 

17 of appropriate BMPs would minimize these effects. This alternative could also require 

18 construction of new transmission lines or upgrades to existing lines. Because the NGCC facility 

19 would be located on an existing site, any new transmission lines could likely be colocated within 

20 existing transmission line corridors to minimize land disturbance. Similarly, any new pipelines 

21 could be colocated within existing pipeline corridors. Although construction activities could 

22 noticeably alter terrestrial resources, primarily through habitat loss or fragmentation, 

23 construction is unlikely to destabilize any important attributes of the terrestrial environment. The 

24 exact magnitude of impacts would vary based on the chosen location of the facility and the 

25 amount and types of undisturbed habitat that would be disturbed for construction of the 

26 alternative, and thus, impacts of construction could range from SMALL to MODERATE.

27 The GEIS (NRC 2013a) concludes that impacts to terrestrial resources from operation of fossil 

28 energy alternatives would essentially be similar to those from continued operations of a nuclear 

29 facility. Unique impacts would include air emissions of GHGs such as nitrogen oxides, carbon 

30 dioxide, and methane, all of which can have far-reaching consequences because they 

31 contribute to climate change. The effects of climate change on terrestrial resources are 

32 discussed in Section 4.13.3.2. Although the impacts of operating the NGCC alternative may be 

33 noticeable, they are unlikely to destabilize any important attribute of the terrestrial environment 

34 and would, therefore, be SMALL.

35 The NRC concludes that the impacts of construction and operation of the NGCC alternative on 

36 terrestrial resources would be SMALL to MODERATE.

37 4.6.6 Combination Alternative (NGCC, Wind, Solar) 

38 The NGCC component of this alternative would require the same amount of land as the NGCC 

39 alternative (94 ac (38 ha)), but the NGCC component would likely make better use of existing 

40 infrastructure because it would be sited at an existing power plant in Illinois or another state 

41 within the ROI and could use buildings and structures that are already in place and operational 

42 for the existing facility. The types of impacts on the terrestrial environment would be similar to 

43 those discussed in Section 4.6.5, but the NRC staff expects the magnitude of impacts to be less 

44 because of the use of existing infrastructure. Thus, the impacts of construction and operation of 

45 the NGCC component of the combination alternative would be SMALL.
Environmental Consequences and Mitigating Actions

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1 The wind component of the combination alternative would require 3,376 ac (1,366 ha) to 

2 10,127 ac (4,098 ha) at sites across the ROI. However, the majority of this land would only be 

3 temporarily disturbed during construction. Permanently disturbed land would hold the wind 

4 turbines, access roads, and transmission lines. Land used for equipment laydown and turbine 

5 component assembly and erection could be returned to its original state. Use of BMPs would 

6 ensure that disturbed lands were appropriately restored to reduce the long-term impacts to the 

7 terrestrial environment. Operation of wind turbines could uniquely affect terrestrial species 

8 through mechanical noise, collision with turbines and meteorological towers, and interference 

9 with migratory behavior. Bat and bird mortality from turbine collisions is an ongoing concern for 

10 operating wind farms; however, recent developments in turbine design have reduced the 

11 potential for bird and bat strikes. The NRC staff expects that this component has the potential 

12 to noticeably alter terrestrial resources, primarily through the loss of habitat and bird and bat 

13 mortalities associated with wind turbine operation. However, it is unlikely that the wind 

14 component would destabilize any important attribute of the terrestrial environment, and thus, 

15 impacts would be MODERATE.

16 The solar component would require 6,749 ac (2,731 ha) of land across the ROI. The majority of 

17 solar installations could be installed on building roofs at existing residential, commercial, or 

18 industrial sites or at larger standalone solar facilities, and thus, it is possible that little terrestrial 

19 habitat would be disturbed during construction. However, the exact magnitude of impacts on 

20 terrestrial resources would depend on the amount of terrestrial habitat that is lost or fragmented 

21 during construction of solar installations. Operation would have no measurable effects on the 

22 terrestrial environment. Overall impacts from construction and operation of this component of 

23 the alternative would range from SMALL to MODERATE depending on the locations of solar 

24 installations and the amount of terrestrial habitat affected.

25 The NRC staff concludes that the impacts of the combination alternative on terrestrial resources 

26 would be SMALL to MODERATE.

27 4.6.7 Purchased Power

28 The purchased power alternative would have wide-ranging impacts that are hard to specifically 

29 assess because this alternative could include a mixture of coal, natural gas, nuclear, and wind 

30 across many different sites in the ROI. This alternative would likely have little to no construction 

31 impacts because it would include power from already-existing power generating facilities. The 

32 construction of additional transmission lines would require implementation of BMPs to minimize 

33 erosion and sedimentation that could affect riparian areas and wetlands. The types of 

34 operational impacts would be similar to the effects discussed in the preceding alternative 

35 sections. This alternative would be more likely to intensify already-existing effects at power 

36 generating facilities than create wholly new effects on terrestrial species and habitats. Existing 

37 facilities would likely have BMPs and other procedures in place to ensure that effects to the 

38 environment during operations are minimized. The NRC staff concludes that the impacts on 

39 terrestrial resources from the purchased power alternative would be SMALL.

40 4.7 Aquatic Resources

41 This section describes the potential impacts of the proposed action (license renewal) and 

42 alternatives to the proposed action on aquatic resources. 
Environmental Consequences and Mitigating Actions

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1 4.7.1 Proposed Action

2 Section 3.1.3 of this SEIS describes the Byron cooling and auxiliary water systems, and 

3 Section 3.7 describes the aquatic resources. The generic (Category 1) and site-specific 

4 (Category 2) issues that apply to aquatic resources at Byron during the proposed license 

5 renewal period appear in Table 4–8. The GEIS (NRC 2013a) discusses these issues in 

6 Section 4.6.1.2.

7 Table 4–8. Aquatic Resource Issues

Issue GEIS Section Category

All plants

Entrainment of phytoplankton and zooplankton 4.6.1.2 1

Infrequently reported thermal impacts 4.6.1.2 1

Effects of cooling water discharge on dissolved oxygen, gas 

supersaturation, and eutrophication 4.6.1.2 1 

Effects of nonradiological contaminants on aquatic organisms 4.6.1.2 1

Exposure of aquatic organisms to radionuclides 4.6.1.2 1

Effects of dredging on aquatic organisms 4.6.1.2 1

Effects on aquatic resources (noncooling system impacts) 4.6.1.2 1

Impacts of transmission line ROW management on aquatic resources (a) 4.6.1.2 1

Losses from predation, parasitism, and disease among organisms 

exposed to sublethal stresses 4.6.1.2 1 

Plants with cooling towers

Impingement and entrainment of aquatic organisms 4.6.1.2 1

Thermal impacts on aquatic organisms 4.6.1.2 1

Plants with cooling ponds or cooling towers using makeup water from a river

Water use conflicts with aquatic resources 4.6.1.2 2

(a) This issue applies only to the inscope portion of electric power transmission lines, which are defined as 

transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional 

power distribution system and transmission lines that supply power to the nuclear plant from the grid.

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51

8 4.7.1.1 Generic GEIS Issues

9 The GEIS (NRC 2013a) concludes that the 11 Category 1 issues listed in Table 4–8 would have 

10 a SMALL impact on aquatic resources during the license renewal term for all plants. For these 

11 issues, no additional plant-specific analysis is required unless new and significant information is 

12 identified.

13 During its review, the NRC staff considered Exelon’s ER, aquatic surveys and studies 

14 performed at Byron and in the Rock River, and available scientific literature; conducted a site 

15 audit; and considered Federal and State agency and public comments received during the 

16 scoping process. The NRC staff did not identify any new and significant information related to
Environmental Consequences and Mitigating Actions

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1 any of the Category 1 issues. Therefore, no site-specific analysis is required for these issues, 

2 and there would be no impacts associated with these issues beyond those discussed in the 

3 GEIS. 

4 4.7.1.2 Water Use Conflicts With Aquatic Resources

5 In the GEIS (NRC 2013a), the NRC staff determined that effects of water use conflicts on 

6 aquatic resources is a Category 2 issue (see Table 4–8) that requires site-specific evaluation 

7 during each license renewal review. Water use conflicts occur when the amount of water 

8 needed to support aquatic resources is diminished as a result of demand for agricultural, 

9 municipal, or industrial use or decreased water availability due to droughts, or a combination of 

10 these factors.

11 According to USGS (2014) data from the nearest surface water gaging station (USGS Station 

12 No. 05440700), the average annual flow of the Rock River at Byron, Illinois, in the past 12 data 

13 years (2001 through 2012) has ranged from 4,834 cfs (139,900 liters per second (L/s) or 

14 2.17 million gallons per minute (gpm)) in 2012 to 12,090 cfs (342,400 L/s or 5.43 million gpm) in 

15 2008. At 100 percent power, Byron’s circulating water system withdraws an average of 

16 2,320 L/s (36,750 gpm) of makeup water. Thus, Byron uses between 0.7 and 1.7 percent of the 

17 Rock River’s flow each year for the past 12 years, under the conservative assumption that 

18 Byron was operating at 100 percent power at all times. In times when the river flow is low, 

19 Byron has an agreement with the Illinois Department of Natural Resources (IDNR) to limit Rock 

20 River water consumption to no more than 9 percent of total river flow when flow is less than 

21 19,200 L/s (679 cfs) (Exelon 2013a). The amount of Rock River water Byron consumes is 

22 minor in comparison to the flow of water past the plant, and regulatory mechanisms are in place 

23 to ensure that Byron does not consume an amount that would be harmful to aquatic biota during 

24 low river flow conditions. The fish species described in Section 3.7 that occur in the Rock River 

25 in the vicinity of the Byron site do not appear to be affected by the consumption of water from 

26 the river. The NRC staff concludes that the impact of water use conflicts on aquatic resources 

27 from the proposed license renewal would be SMALL.

28 4.7.2 No-Action Alternative

29 If Byron were to cease operating, impacts to aquatic ecology would decrease or stop following 

30 reactor shutdown. Some withdrawal of water from the Rock River would continue during the 

31 shutdown period as the fuel is cooled, although the amount of water withdrawn would decrease 

32 over time. The reduced demand for cooling water would further decrease the effects of 

33 impingement, entrainment, and thermal effluents, which were determined to be SMALL for 

34 Byron during the proposed license renewal term (see Section 4.7.1.1). These effects would 

35 likely stop following the removal of fuel assemblies from the reactor cores.

36 NUREG–0586, Generic Environmental Impact Statement on Decommissioning of Nuclear 

37 Facilities, Supplement 1, concludes generically that impacts to aquatic ecology during

38 decommissioning activities would be SMALL for facilities at which the decommissioning 

39 activities would be limited to existing operational areas (NRC 2002). In the case of Byron, the 

40 NRC staff did not identify any effects that would have more than minor impacts on aquatic 

41 resources. Thus, the NRC staff concludes that the impacts of the no-action alternative on 

42 aquatic resources during the proposed license renewal term would be SMALL.

43 4.7.3 New Nuclear Alternative

44 Construction of a new nuclear alternative would occur at an existing power plant site (other than 

45 the Byron site) or at a retired coal plant site outside of Illinois. Construction activities could 
Environmental Consequences and Mitigating Actions

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1 degrade water quality of nearby streams, ponds, or rivers through erosion and sedimentation; 

2 result in loss of habitat through pond or wetland filling; or result in direct mortality of aquatic 

3 organisms from dredging or other inwater work. Due to the short-term nature of construction 

4 activities, these effects would likely be relatively localized and temporary. Siting the plant on an 

5 existing site could make use of existing transmission lines, roads, parking areas, and other 

6 infrastructure, which would limit the amount of habitat disturbance that would be required. Less 

7 habitat disturbance would create less erosion and sedimentation. The construction of intake 

8 and discharge structures could result in direct mortality of individuals as well as water quality 

9 degradation. Appropriate permits would ensure that water quality impacts would be addressed 

10 through mitigation or BMPs, as stipulated in the permits. The U.S. Environmental Protection 

11 Agency, USACE, or the State would oversee applicable permitting, including a Clean Water Act 

12 Section 404 permit, Section 401 certification, and Section 402(p) NPDES general stormwater

13 permit. The NRC (2013g) has completed the review of one combined license (COL) application 

14 to build and operate a new nuclear plant in the ROI (Enrico Fermi 3 in Michigan) and found that 

15 construction would have SMALL impacts on aquatic resources. Without more specific details on 

16 the location of the new nuclear alternative, the NRC staff finds it reasonable to adopt previous 

17 conclusions regarding Enrico Fermi 3 for the construction portion of this alternative.

18 Operational impacts would include those listed in Table 4–8, and the GEIS (NRC 2013a) 

19 conclusions of SMALL for Category 1 issues in the table would apply during the operational 

20 phase of the new nuclear alternative. Water use conflicts with aquatic resources would depend 

21 on the site location, water body, and specific aquatic community present and cannot be 

22 determined without more-specific details on the location of this alternative.

23 The NRC staff concludes that the impacts to aquatic resources from construction and operation 

24 of a new nuclear alternative would be SMALL.

25 4.7.4 IGCC Alternative

26 Construction of an IGCC alternative would occur at the Byron site or another existing power 

27 plant site in the ROI. The GEIS (NRC 2013a) indicates that the impacts of new power plant 

28 construction on ecological resources would be qualitatively similar. Thus, those impacts 

29 discussed under the new nuclear alternative would apply during the construction phase. 

30 Because the IGCC alternative would require significantly more land than the new nuclear 

31 alternative (2,000 ac (809 ha) versus 355 ac (144 ha)), the magnitude of impacts would likely be 

32 greater and could create noticeable effects on aquatic resources. Thus, construction impacts 

33 would be MODERATE.

34 Operation of the IGCC alternative would require less cooling water than Byron. Accordingly, 

35 impingement, entrainment, and thermal effects on aquatic resources would likely be smaller 

36 than for continued operation of Byron, though the exact magnitude would depend upon the 

37 water body and specific aquatic communities present. Chemical discharges from the cooling 

38 system would be similar to those at Byron. Operation would require coal deliveries, cleaning, 

39 and storage, which would require periodic dredging (if coal is delivered by barge); create dust, 

40 sedimentation, and turbidity; and introduce trace elements and minerals into the water. Air

41 emissions from the IGCC units would include small amounts of sulfur dioxide, particulates, and 

42 mercury that would settle on water bodies or be introduced into the water from soil erosion. If 

43 the IGCC plant were located on the same water body (the Rock River) in the vicinity of the 

44 Byron site, overall operational impacts would be similar to the continued operation of Byron with 

45 the exception of air emissions. However, without knowing the location of the IGCC plant, the 

46 associated water body, aquatic species, and their interactions within the ecosystem, the NRC 

47 staff cannot assume that overall impacts of operation of an IGCC plant would not create 
Environmental Consequences and Mitigating Actions

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1 noticeable effects on the aquatic environment. Thus, impacts could range from SMALL to 

2 MODERATE.

3 The NRC staff concludes that the impacts to aquatic resources from construction of an IGCC 

4 plant would be MODERATE and the impacts of operation would be within the range of SMALL 

5 to MODERATE. 

6 4.7.5 NGCC Alternative

7 Construction of an NGCC alternative would occur at the Byron site or another existing power 

8 plant site in the ROI. The GEIS (NRC 2013a) indicates that the impacts of new power plant 

9 construction on ecological resources would be qualitatively similar. Thus, those impacts 

10 discussed under the new nuclear alternative would apply during the construction phase. 

11 Construction of new pipelines, if necessary, could impact previously undisturbed habitats. This 

12 impact would vary depending on the location of the plant and would be more likely to impact 

13 terrestrial resources than aquatic resources. Because the NGCC alternative would be built on 

14 an existing power plant site, new pipelines could be colocated in existing corridors to reduce 

15 impacts. Overall, construction impacts would be SMALL.

16 Operation of the NGCC alternative cooling system would be qualitatively similar to the IGCC 

17 alternative but would result in smaller impacts because the NGCC alternative would consume 

18 less cooling water. Air emissions from the NGCC units would include nitrogen oxide, carbon 

19 dioxide, and particulates that would settle on water bodies or be introduced into the water from 

20 soil erosion. If the NGCC plant were located on the same water body (the Rock River) in the 

21 vicinity of the Byron site, overall operational impacts would be less than for the continued 

22 operation of Byron. However, without knowing the location of the NGCC plant, the associated 

23 water body, aquatic species, and their interactions within the ecosystem, the NRC staff cannot 

24 assume that overall impacts of operation of an NGCC plant would not create noticeable effects 

25 on the aquatic environment. Thus, impacts could range from SMALL to MODERATE.

26 The NRC staff concludes that the impacts to aquatic resources from construction of an NGCC 

27 plant would be SMALL and the impacts of operation would be within the range of SMALL to 

28 MODERATE.

29 4.7.6 Combination Alternative (NGCC, Wind, Solar)

30 The NGCC portion of this alternative could be located at the Byron site or another existing 

31 power plant site in the ROI. Construction and operation impacts would be qualitatively similar to 

32 those discussed for the NGCC alternative, but would be much lower in magnitude due to the 

33 smaller footprint of the plant, reduced cooling water consumption, and lowered air emissions. 

34 The wind and solar portions of the alternative, which account for 90 percent of the alternative’s 

35 power generation, would not require cooling or consumptive water use during operation, and 

36 thus, would not affect aquatic resources. The NRC staff concludes that the impacts on aquatic 

37 resources from the combination alternative would be SMALL.

38 4.7.7 Purchased Power

39 The purchased power alternative would have wide-ranging impacts that are hard to specifically 

40 assess because this alternative could include a mixture of coal, natural gas, nuclear, and wind 

41 across many different sites in the ROI. This alternative would likely have little to no construction 

42 impacts because it would include power from already-existing power generating facilities. The 

43 construction of additional transmission lines would require implementation of BMPs to minimize 

44 erosion and sedimentation in nearby streams, ponds, or rivers. The types of operational 
Environmental Consequences and Mitigating Actions

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1 impacts would be similar to the effects discussed in the preceding alternative sections. This 

2 alternative would be more likely to intensify already-existing effects at power generating facilities 

3 than create wholly new effects on aquatic species and habitats. Existing facilities would likely 

4 have BMPs and other procedures in place to ensure that effects to the environment during 

5 operations are minimized. The NRC staff concludes that the impacts on aquatic resources from 

6 the purchased power alternative would be SMALL.

7 4.8 Special Status Species and Habitats

8 This section describes the potential impacts of the proposed action (license renewal) and 

9 alternatives to the proposed action on special status species and habitats. 

10 4.8.1 Proposed Action

11 Section 3.8 of this SEIS describes the special status species and habitats that have the 

12 potential to be affected by the proposed action. The discussion of species and habitats 

13 protected under the Endangered Species Act of 1973 (16 U.S.C. § 1531 et seq., herein referred 

14 to as ESA), includes a description of the action area as defined by the ESA section 7 

15 regulations at 50 CFR 402.02. The action area encompasses all areas that would be directly or 

16 indirectly affected by the proposed Byron license renewal.

17 Table 4–9 lists the one Category 2 issue related to special status species and habitats identified 

18 in the GEIS (NRC 2013a). Appendix D.1 contains information on the NRC staff’s section 7 

19 consultation with the U.S. Fish and Wildlife Service (FWS) for the proposed action. The NRC 

20 did not consult with the National Marine Fisheries Service (NMFS) as part of the Byron license 

21 renewal review because (as described in Sections 3.8 and 4.8.1.1) no species or habitats under 

22 NMFS’s jurisdiction occur within the action area.

23 Table 4–9. Special Status Species and Habitat Issues

Issue GEIS Section Category

Threatened, endangered, and protected species, critical habitat and 

essential fish habitat 4.6.1.3 2 

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51

24 4.8.1.1 Species and Habitats Protected Under the Endangered Species Act

25 Species and Habitats Under the FWS’s Jurisdiction

26 Section 3.8 considers whether the four Federally listed species and one proposed species

27 identified in Table 4–10 occur in the action area based on each species’ habitat requirements, 

28 life history, and other available information. In that section, the NRC staff concludes that none 

29 of these species are likely to occur in the action area. The NRC staff also concludes that no 

30 candidate species, or proposed or designated critical habitat occur in the action area. Thus, the 

31 NRC staff concludes that the proposed action would have no effect on Federally listed species 

32 or habitats under FWS’s jurisdiction.

33 If in the future, a Federally listed species is observed on the Byron site, the NRC has measures 

34 in place to ensure that NRC staff would be appropriately notified so that the NRC staff could 

35 determine the appropriate course of action, such as possibly reinitiating section 7 consultation 

36 under the ESA with the FWS at that time. Byron’s operating licenses, Appendix B, 
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1 “Environmental Protection Plan,” Section 4.1, “Unusual or Important Environmental Events” 

2 (NRC 1985, 1987) require Exelon to report to the NRC within 24 hours any occurrence of a 

3 species protected by the ESA on the Byron site. Additionally, the NRC’s regulations containing 

4 notification requirements require that operating nuclear power reactors report to the NRC within 

5 4 hours “any event or situation, related to...protection of the environment, for which a news 

6 release is planned or notification to other government agencies has been or will be made” (Title 

7 10 of the Code of Federal Regulations (10 CFR) 50.72(b)(2)(xi)). Such notifications include 

8 reports regarding Federally listed species, as described in Section 3.2.12 of NUREG–1022, 

9 Event Report Guidelines: 10 CFR 50.72 and 50.73 (NRC 2013b). 

10 Table 4–10. Effect Determinations for Federally Listed Species

Species Common Name Federal Status (a) Effect Determination

Mammals

Myotis septentrionalis northern long-eared bat P no effect

Myotis sodalis Indiana bat E no effect

Plants

Lespedeza leptostachya prairie bush clover T no effect

Platanthera leucophaea eastern prairie fringed orchid T no effect

Dalea foliosa leafy prairie clover E no effect

(a) E = endangered; T = threatened; P = proposed for Federal listing

Sources: Exelon 2013a; FWS 2013a, 2013b

11 Species and Habitats Under NMFS’s Jurisdiction

12 As discussed in Section 3.8, no species or habitats under NMFS’s jurisdiction occur within the 

13 action area. Thus, the NRC staff concludes that the proposed action would have no effect on 

14 Federally listed species or habitats under NMFS’s jurisdiction.

15 Cumulative Effects

16 The ESA regulations at 50 CFR 402.12(f)(4) direct Federal agencies to consider cumulative 

17 effects as part of the proposed action effects analysis. Under the ESA, cumulative effects are 

18 defined as “those effects of future State or private activities, not involving Federal activities, that 

19 are reasonably certain to occur within the action area of the Federal action subject to 

20 consultation” (50 CFR 402.02). Unlike the NEPA definition of cumulative impacts (see 

21 Section 4.16), cumulative effects under the ESA do not include past actions or other Federal 

22 actions requiring separate ESA section 7 consultation. When formulating biological opinions 

23 under formal section 7 consultation, the FWS and NMFS (1998) consider cumulative effects 

24 when determining the likelihood of jeopardy or adverse modification. Therefore, consideration 

25 of cumulative effects under the ESA is necessary only if listed species will be adversely affected 

26 by the proposed action (FWS 2014).

27 In the case of Byron, because the NRC staff concluded earlier in this section that the proposed 

28 license renewal would have no effect on listed, proposed, or candidate species or on designated 

29 or proposed critical habitat, consideration of cumulative effects is not necessary.
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1 4.8.1.2 Species and Habitats Protected Under the Magnuson–Stevens Act

2 As discussed in Section 3.8, NMFS has not designated essential fish habitat (EFH) pursuant to 

3 the Magnuson–Stevens Fishery Conservation and Management Act, as amended 

4 (16 U.S.C. §§ 1801–1884; herein referred to as MSA) in the Rock River. Thus, the NRC staff 

5 concludes that the proposed action would have no effect on EFH.

6 4.8.2 No-Action Alternative

7 Under the no-action alternative, Byron would shut down. Federally listed species and 

8 designated critical habitat can be affected not only by operation of nuclear power plants but also 

9 by activities during shutdown. The ESA action area for the no-action alternative would most 

10 likely be the same or similar to the action area described in Section 3.8. The plant would 

11 require substantially less cooling water, so potential impacts to aquatic species and habitats 

12 would be reduced, although the plant would still require some cooling water for some time. 

13 Changes in land use and other shutdown activities might affect terrestrial species differently 

14 than under continued operation.

15 Because no Federally listed species or habitats occur in the action area, the no-action 

16 alternative would likely have no effect on any such species or habitats. However, NRC would 

17 assess the need for ESA consultation upon plant shutdown. The ESA forbids “take” of a listed 

18 species, where “take” means “harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or 

19 collect, or attempt to engage in any such conduct.” In the case of a take, ESA section 7 

20 requires that NRC initiate consultation with the FWS or NMFS. The implementing regulations at 

21 50 CFR 402.16 also direct Federal agencies to reinitiate consultation in circumstances 

22 where (a) the incidental take limit in a biological opinion is exceeded, (b) new information 

23 reveals effects to Federally listed species or designated critical habitats that were not previously 

24 considered, (c) the action is modified in a manner that causes effects not previously considered, 

25 or (d) new species are listed or new critical habitat is designated that may be affected by the 

26 action. An ESA section 7 consultation could identify impacts on Federally listed species or 

27 critical habitat, require monitoring and mitigation to minimize such impacts, and provide a level 

28 of exempted takes. Regulations and guidance regarding the ESA section 7 consultation 

29 process are provided in 50 CFR Part 402 and in the Endangered Species Consultation 

30 Handbook (FWS and NMFS 1998).

31 The effects on ESA-listed aquatic species would likely be smaller than the effects under 

32 continued operation but would depend on the listed species and habitats present when the 

33 alternative is implemented. The types and magnitudes of adverse impacts to terrestrial 

34 ESA-listed species would depend on the shutdown activities and the listed species and habitats 

35 present when the alternative is implemented, and thus, the NRC cannot forecast a particular 

36 level of impact for this alternative.

37 4.8.3 New Nuclear Alternative

38 This alternative entails shutdown and decommissioning of Byron and construction of a new 

39 nuclear alternative at an existing power plant site (other than the Byron site) or at a retired coal 

40 plant site outside of Illinois. Section 4.8.2 discusses ESA considerations for the shutdown of 

41 Byron.

42 Because the new nuclear alternative would be built outside of Illinois, the special status species 

43 and habitats affected by the action would be different from those considered under the proposed 

44 action. Because NRC would remain the licensing agency under this alternative, the ESA would 

45 require NRC to initiate consultation with the FWS and NMFS, as applicable, prior to construction 
Environmental Consequences and Mitigating Actions

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1 to ensure that the construction and operation of the new nuclear plant would not adversely 

2 affect any Federally listed species or adversely modify or destroy designated critical habitat. 

3 In the unlikely event that the new nuclear plant is sited in an area that could affect water bodies 

4 with designated EFH, which applies to only certain commercially harvested marine and 

5 anadromous fish species, consultation with NMFS under the MSA would be required to assess 

6 potential impacts to that habitat. 

7 Because the types and magnitudes of adverse impacts to ESA-listed species and EFH would 

8 depend on the proposed site, plant design, operation, and species and habitats listed when the 

9 alternative is implemented, the NRC cannot forecast a particular level of impact for this 

10 alternative.

11 4.8.4 IGCC Alternative

12 This alternative entails shutdown and decommissioning of Byron and construction of a new 

13 IGCC facility at the Byron site or another existing power plant site in the ROI. Section 4.8.2 

14 discusses ESA considerations for the shutdown of Byron.

15 Unlike the new nuclear alternative, the NRC does not license IGCC facilities, and the NRC 

16 would not be responsible for initiating section 7 consultation if listed species or habitats might be 

17 adversely affected under this alternative. The facilities themselves would be responsible for 

18 protecting listed species because the ESA forbids take of a listed species. 

19 If the IGCC alternative were to be built on the Byron site, the ESA action area might be different, 

20 and the activities and structures associated with the site would be different from those described 

21 for the proposed license renewal. If the IGCC alternative were to be built on a site other than 

22 the Byron site, the listed species and habitats affected by the action would be different from

23 those identified for Byron. Because the types and magnitudes of adverse impacts to ESA-listed 

24 species would depend on the proposed site, plant design, operation, and species and habitats 

25 listed when the alternative is implemented, the NRC cannot forecast a particular level of impact 

26 for this alternative.

27 4.8.5 NGCC Alternative

28 This alternative entails shutdown and decommissioning of Byron and construction of a new 

29 NGCC facility at the Byron site or another existing power plant site in the ROI. Section 4.8.2 

30 discusses ESA considerations for the shutdown of Byron.

31 Unlike the new nuclear alternative, the NRC does not license NGCC facilities, and the NRC 

32 would not be responsible for initiating section 7 consultation if listed species or habitats might be 

33 adversely affected under this alternative. The facilities themselves would be responsible for 

34 protecting listed species because the ESA forbids take of a listed species. 

35 If the NGCC alternative were to be built on the Byron site, the ESA action area might be 

36 different, and the activities and structures associated with the site would be different from those 

37 described for the proposed license renewal. If the NGCC alternative were to be built on a site 

38 other than the Byron site, the listed species and habitats affected by the action would be 

39 different from those identified for Byron. Because the types and magnitudes of adverse impacts 

40 to ESA-listed species would depend on the proposed site, plant design, operation, and species 

41 and habitats listed when the alternative is implemented, the NRC cannot forecast a particular 

42 level of impact for this alternative.
Environmental Consequences and Mitigating Actions

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1 4.8.6 Combination Alternative (NGCC, Wind, Solar)

2 This alternative entails shutdown and decommissioning of Byron and construction and operation 

3 of a new NGCC plant at the Byron site or another existing power plant site in the ROI as well as 

4 wind turbines and solar PV systems throughout the ROI. Section 4.8.2 discusses ESA

5 considerations for the shutdown of Byron.

6 Unlike the new nuclear alternative, the NRC does not license NGCC, wind, and solar facilities, 

7 and the NRC would not be responsible for initiating section 7 consultation if listed species or 

8 habitats might be adversely affected under this alternative. The facilities themselves would be 

9 responsible for protecting listed species because the ESA forbids take of a listed species. 

10 If part of the combination alternative were to be built on the Byron site, the ESA action area 

11 might be different, and the activities and structures associated with the site would be different 

12 from those described under continued operation. If parts of the combination alternative were to 

13 be built on a site or sites other than the Byron site, the listed species and habitats affected by 

14 the action would be different from those identified for Byron. Because the types and 

15 magnitudes of adverse impacts to ESA-listed species would depend on the proposed site, 

16 alternative design, operation, and species and habitats listed when the alternative is 

17 implemented, the NRC cannot forecast a particular level of impact for this alternative.

18 4.8.7 Purchased Power

19 Because the purchased power alternative would include a mixture of coal, natural gas, nuclear, 

20 and wind across many different sites in the ROI, the special status species and habitats affected 

21 by the action would be different from those considered under the proposed action. This 

22 alternative would be more likely to intensify already-existing effects at existing power generating 

23 facilities than create wholly new effects on protected species and habitats. Because the types 

24 and magnitudes of adverse impacts to ESA-listed species would depend on the proposed sites, 

25 plant designs, operation, and species and habitats listed at the various sites when the 

26 alternative is implemented, the NRC cannot forecast a particular level of impact for this 

27 alternative. As with the other alternatives discussed previously, the facilities themselves, and 

28 not the NRC, would be responsible for initiating section 7 consultation if listed species or 

29 habitats might be adversely affected under this alternative. The NRC cannot forecast a 

30 particular level of impact for this alternative.

31 4.9 Historic and Cultural Resources

32 This section describes the potential impacts of the proposed action (license renewal) and 

33 alternatives to the proposed action on historic and cultural resources. 

34 4.9.1 Proposed Action

35 The historic and cultural resource issue applicable to Byron during the license renewal term is 

36 listed in Table 4–11. Section 3.9 of this SEIS describes the historic and cultural resources that 

37 have the potential to be affected by the proposed action. 
Environmental Consequences and Mitigating Actions

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1 Table 4–11. Historic and Cultural Resources 

Issue GEIS Section Category

Historic and Cultural Resources 4.7.1 2 

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

2 The National Historic Preservation Act of 1966, as amended (NHPA), requires Federal agencies 

3 to consider the effects of their undertakings on historic properties, and renewing the operating 

4 license of a nuclear power plant is an undertaking that could potentially affect historic properties. 

5 Historic properties are defined as resources eligible for listing in the National Register of Historic 

6 Places (NRHP). The criteria for eligibility are listed in 36 CFR Part 60.4 and include 

7 (1) association with significant events in history; (2) association with the lives of persons 

8 significant in the past; (3) embodiment of distinctive characteristics of type, period, or 

9 construction; and (4) sites or places that have yielded, or are likely to yield, important 

10 information.

11 The historic preservation review process (Section 106 of the NHPA) is outlined in regulations 

12 issued by the Advisory Council on Historic Preservation (ACHP) in 36 CFR Part 800.

13 In accordance with the provisions of the NHPA, the NRC is required to make a reasonable effort 

14 to identify historic properties included in or eligible for inclusion in the NRHP in the area of 

15 potential effect (APE). The APE for a license renewal action is the area at the power plant site, 

16 the transmission lines up to the first substation and immediate environs that may be affected by 

17 the license renewal decision, and land-disturbing activities associated with continued reactor

18 operations. For Byron, the first substation is located on site at the 345-kV Byron Station 

19 switchyard (Exelon 2013b).

20 If historic properties are present within the APE, the NRC is required to contact the State 

21 Historic Preservation Office, assess the potential impact, and resolve any possible adverse 

22 effects of the undertaking (license renewal) on historic properties. In addition, the NRC is 

23 required to notify the State Historic Preservation Office if historic properties would not be 

24 affected by license renewal or if no historic properties are present. The State Historic 

25 Preservation Office is part of the Illinois Historic Preservation Agency (IHPA).

26 Consultation

27 In accordance with 36 CFR 800.8(c), on August 9, 2013, the NRC initiated consultations on the 

28 proposed action by writing to the ACHP and IHPA (NRC 2013d, 2013e). Also on 

29 August 9, 2013, the NRC initiated consultation with the following 14 Federally recognized tribes 

30 (NRC 2013f) (see Appendix D for a copy of these letters):

31 • Ho-Chunk Nation; 

32 • Miami Tribe of Oklahoma; 

33 • Peoria Tribe of Indians of Oklahoma; 

34 • Citizen Potawatomi Nation; 

35 • Sac and Fox Tribe of the Mississippi in lowa/Meskwaki Nation;

36 • Sac and Fox Nation of Missouri in Kansas and Nebraska; 

37 • Sac and Fox Nation; 
Environmental Consequences and Mitigating Actions

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1 • Pokagon Band of Potawatomi; 

2 • Forest County Potawatomi; 

3 • Hannahville Indian Community, Band of Potawatomi; 

4 • Prairie Band Potawatomi Nation; 

5 • Winnebago Tribe of Nebraska; 

6 • Kickapoo Tribe in Kansas; and

7 • Kickapoo Tribe of Oklahoma. 

8 By letter, the NRC provided information about the proposed action, defined the APE, and 

9 indicated that the NHPA review would be integrated with the NEPA process, according to 

10 36 CFR 800.8. NRC invited participation in the identification and possible decisions concerning 

11 historic properties and also invited participation in the scoping process. The NRC received no 

12 scoping comments from any of the tribes contacted. In September 2013, the NRC received a 

13 determination from the IHPA stating no objection to the undertaking and that no historic 

14 properties would be affected (IHPA 2013) (see Appendix D).

15 Exelon currently has no planned physical changes or license renewal-related ground-disturbing 

16 activities at the Byron site (Exelon 2013b). As described in Section 3.9, there are no historic 

17 properties or known NRHP-eligible historic or cultural resources located within the Byron APE. 

18 However, non-NRHP eligible cultural resources are present within the APE and approximately 

19 400 ac of the Byron site is undisturbed land (Exelon 2013b). Furthermore, the Illinois Inventory 

20 of Archaeological Sites has identified the area along the banks of the Rock River in the Byron 

21 site as having archaeological resource potential (ISM 2014). As a result, Exelon established a 

22 draft Cultural Resource Management Plan (CRMP) to ensure historic and cultural resources are 

23 considered prior to any ground-disturbing activities at Byron. The CRMP identifies locations of 

24 known historic and cultural resource sites and previously disturbed areas within Byron property. 

25 The CRMP also instructs Exelon staff on how to evaluate land-disturbing activity for possible 

26 impacts to historic and cultural resources (Exelon 2013b). If historic or cultural resources are 

27 inadvertently discovered during operational activities, the CRMP directs Exelon staff to stop 

28 work, protect exposed resources, and contact Exelon environmental personnel to take 

29 appropriate action (Exelon 2013b). Supplemental cultural resource surveys may be performed 

30 on the affected areas based on consultation with the State Historic Preservation Office. 

31 Day-to-day maintenance of the Byron site follows guidelines based on the type of land use, and 

32 less developed areas are not regularly landscaped unless specially requested. Land known to 

33 contain historic and cultural resources on the Byron site is not maintained any differently than 

34 other landscapes within the property (Exelon 2013b).

35 Based on (1) there being currently no NRHP-eligible historic properties in the APE, (2) tribal 

36 input, (3) Exelon’s draft CRMP, (4) the fact that no license renewal-related physical changes or 

37 ground-disturbing activities would occur, (5) IHPA input, and (6) cultural resource assessment, 

38 license renewal would not affect any known historic properties (36 CFR Section 800.4(d)(1)). 

39 Exelon could reduce the risk of potential impacts to historic and cultural resources located on or 

40 near the Byron site by finalizing their draft CRMP, with input from the State Historic Preservation 

41 Office, and by providing training on cultural resources for Exelon staff engaged in planning and 

42 executing ground-disturbing activities.
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1 4.9.2 No-Action Alternative

2 Not renewing the operating licenses and terminating reactor operations would have no effect on 

3 historic properties and cultural resources on or in the immediate vicinity of Byron. A separate 

4 environmental review would be conducted to determine the impacts of decommissioning 

5 activities on historic properties and cultural resources.

6 4.9.3 New Nuclear Alternative

7 Any land areas potentially affected by the construction and operation of a new nuclear 

8 alternative power plant would need to be surveyed to identify and record historic and 

9 archaeological cultural resources. An inventory of a previously disturbed former plant industrial 

10 site may still be necessary if the site has not been previously surveyed or to verify the level of 

11 previous disturbance and to evaluate the potential for intact subsurface cultural resources to be 

12 present. All potentially affected land areas would need to be surveyed, including land required 

13 for new roads, transmission corridors, other right-of-ways (ROWs). Any cultural resources 

14 found during these surveys would need to be evaluated for eligibility for listing on the NRHP. 

15 Mitigation of adverse effects would need to be considered if eligible resources were 

16 encountered. Areas with the greatest sensitivity and most significant cultural resources should 

17 be avoided. Visual impacts on significant cultural resources, such as the viewsheds of historic 

18 properties near the proposed power plant site, should also be assessed and evaluated.

19 The potential for impacts to historic and cultural resources from the construction and operation 

20 of a new nuclear power plant would vary greatly depending on the location of the site. Cooling 

21 towers could impact historic property viewsheds. However, given that the preference is to 

22 construct a new nuclear power plant at a previously disturbed former power plant site, 

23 avoidance of undisturbed land could further reduce potential impacts to historic and cultural 

24 resources. Therefore, the impacts on historic and cultural resources from the construction and 

25 operation of a new nuclear power plant would be SMALL.

26 4.9.4 IGCC Alternative

27 Any areas potentially affected by the construction and operation of an IGCC power plant would 

28 need to be surveyed to identify and record historic and cultural resources. If the IGCC power 

29 plant is constructed at the existing Byron site, previously disturbed areas known to not contain 

30 historic and cultural resources could be used. If the power plant is sited on the approximately 

31 400 ac (162 ha) of undisturbed land on the Byron site, a survey and inventory of potential

32 historic and cultural resources would need to be performed. If the IGCC power plant is sited at

33 an existing power plant site other than Byron, a cultural resource survey may still be necessary 

34 if the site has not been previously surveyed or to verify the level of disturbance and evaluate the 

35 potential for intact subsurface resources. Any resources found in these surveys would need to 

36 be evaluated for eligibility on the NRHP, and mitigation of adverse effects would need to be 

37 addressed if eligible resources were encountered. Areas with the greatest sensitivity should be 

38 avoided. Visual impacts on significant cultural resources, such as the viewsheds of historic 

39 properties near the proposed power plant site, should also be assessed and evaluated.

40 The potential for impacts on historic and cultural resources from the construction and operation 

41 of an IGCC power plant would vary greatly depending on the location of the proposed site. 

42 Given that the preference is to use a previously disturbed former power plant site and no major 

43 infrastructure upgrades are necessary, avoidance of significant historic and cultural resources 

44 should be possible and effectively managed under current laws and regulations. Therefore, the

45 impacts on historic and cultural resources from the IGCC alternative would be SMALL.
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1 4.9.5 NGCC Alternative

2 Any areas potentially affected by the construction and operation of an NGCC power plant would 

3 need to be surveyed to identify and record historic and cultural resources. If the NGCC power 

4 plant is constructed at the existing Byron site, previously disturbed areas known to not contain 

5 historic and cultural resources could be used. If the power plant is sited on the approximately 

6 400 ac (162 ha) of undisturbed land on the Byron site, a survey and inventory of potential

7 historic and cultural resources would need to be performed. If the NGCC power plant is sited at

8 an existing power plant site other than Byron, a cultural resource survey may still be necessary 

9 if the site has not been previously surveyed or to verify the level of disturbance and evaluate the 

10 potential for intact subsurface resources. Additionally, plant operators would need to survey all 

11 areas associated with the alternative (e.g., a new pipeline, roads, transmission corridors, other 

12 ROWs). Any resources found in these surveys would need to be evaluated for eligibility on the 

13 NRHP, and mitigation of adverse effects would need to be addressed if eligible resources were 

14 encountered. Areas with the greatest sensitivity should be avoided. Visual impacts on 

15 significant cultural resources, such as the viewsheds of historic properties near the proposed 

16 power plant site, should also be assessed and evaluated.

17 The potential for impacts on historic and cultural resources from the construction and operation 

18 of an NGCC power plant would vary greatly depending on the location of the proposed site. 

19 Given that the preference is to use a previously disturbed former power plant site, avoidance of 

20 significant historic and cultural resources should be possible and effectively managed under 

21 current laws and regulations. However, historic and archaeological resources could potentially 

22 be affected, depending on the resource richness of the land required for a new gas pipeline. 

23 Therefore, the impacts on historic and cultural resources from the NGCC alternative would be 

24 SMALL to MODERATE.

25 4.9.6 Combination Alternative (NGCC, Wind, Solar)

26 Areas potentially affected by the construction and operation of an NGCC power plant and wind 

27 and solar PV power generating facilities would need to be surveyed to identify and record 

28 historic and archaeological resources. Any historic and cultural resources found in these 

29 surveys would need to be evaluated for eligibility on the NRHP, and mitigation of adverse 

30 effects would need to be addressed if eligible resources were encountered.

31 Impacts to historic and cultural resources from the NGCC portion of this alternative would be

32 similar to the NGCC alternative in Section 4.9.5. The potential for impacts on historic and 

33 cultural resources from the wind portion of this alternative would vary greatly, depending on the 

34 location of the proposed sites. Areas with the greatest cultural sensitivity could be avoided or 

35 effectively managed under current laws and regulations. Construction of wind farms and their 

36 support infrastructure could impact historic and cultural resources because of earthmoving 

37 activities (e.g., grading and digging) and the aesthetic changes to the viewshed of historic 

38 properties located nearby. The impacts of the construction of a new solar PV alternative on 

39 historic and cultural resources would vary depending on the form of the solar capacity installed. 

40 Rooftop installations minimize land disturbance and the modifications necessary to the 

41 transmission system, thereby minimizing impacts to historic and cultural resources. Land-based 

42 installations would be larger than rooftop installations and will require some degree of land 

43 disturbance for installation purposes, potentially causing greater impacts to historic and cultural

44 resources. Aesthetic changes caused by the installation of both forms could have a noticeable 

45 effect on the viewshed of nearby historic properties. Using previously disturbed sites for 

46 land-based installations and colocating any new transmission lines with existing ROWs could 

47 minimize impacts to historic and cultural resources. Areas with the greatest amount of 
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1 significant resources could be avoided or effectively managed under current laws and 

2 regulations. Therefore, depending on the resource richness of the sites chosen for the NGCC, 

3 wind, and solar PV alternative, the impacts on historic and cultural resources could range from 

4 SMALL to LARGE.

5 4.9.7 Purchased Power

6 No direct impacts on historic and cultural resources are expected from purchased power. If new 

7 transmission lines were needed to convey power to the PJM Interconnection area, surveys 

8 similar to those discussed in Section 4.9.3 would need to be performed. However, transmission 

9 lines would likely be colocated with existing ROWs minimizing any impacts to historic and 

10 cultural resources.

11 Indirectly, construction of new nuclear, coal-fired, and natural gas-fired plants, or wind energy 

12 projects, and any new transmission lines to support increased demand in the purchased power 

13 alternative could affect historic and cultural resources. Any areas potentially affected by 

14 construction would need to be surveyed to identify and record historic and cultural resources. 

15 Resources found in these surveys would need to be evaluated for eligibility on the NRHP, and 

16 mitigation of adverse effects would need to be addressed if eligible resources were 

17 encountered. Plant operators would need to survey all areas associated with operation of the 

18 alternative (e.g., roads, transmission corridors, other ROWs). The potential for impacts on 

19 historic and cultural resources would vary greatly depending on the location of the proposed 

20 sites; however, using previously disturbed sites could greatly minimize impacts to historic and 

21 cultural resources. Areas with the greatest sensitivity could be avoided or effectively managed 

22 under current laws and regulations. Therefore, depending on the resource richness of the sites 

23 chosen, the impacts on historic and cultural resources could range from SMALL to LARGE.

24 4.10 Socioeconomics

25 In license renewal environmental reviews, the NRC considers the environmental consequences

26 of the proposed action (i.e., continued reactor operations), the no-action alternative (i.e., not 

27 renewing the operating license), and the environmental consequences of various alternatives for 

28 replacing the nuclear power plant’s generating capacity. In plant-specific environmental 

29 reviews, the NRC staff compares the environmental impacts of license renewal with those of the 

30 no-action alternative and replacement power alternatives to determine whether the adverse 

31 environmental impacts of license renewal are great enough to deny the option of license 

32 renewal for energy-planning decisionmakers.

33 4.10.1 Proposed Action

34 The Category 1 (generic) socioeconomic NEPA issues in 10 CFR Part 51, Appendix B to 

35 Subpart A, Table B-1, applicable to the license renewal of Byron are shown in Table 4–12. 

36 No Category 2 socioeconomic NEPA issues were identified during the review conducted for the 

37 2013 GEIS revision (NRC 2013a). Socioeconomic effects of ongoing reactor operations at 

38 Byron have become well-established as regional socioeconomic conditions have adjusted to the 

39 presence of the nuclear power plant. These conditions are described in Section 3.10. Any 

40 changes in employment and tax payments caused by license renewal and any associated 

41 refurbishment activities could have a direct and indirect impact on community services and 

42 housing demand, as well as traffic volumes in the communities around a nuclear power plant.
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1 Table 4–12. Socioeconomic NEPA Issues Affected by License Renewal

Issue GEIS Section Category

Employment and income, recreation, and tourism 4.8.1.1 1

Tax revenues 4.8.1.2 1

Community services and education 4.8.1.3 1

Population and housing 4.8.1.4 1

Transportation 4.8.1.5 1

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51

2 The supplemental site-specific socioeconomic impact analysis for the license renewal of Byron 

3 included a review of Exelon’s ER (Exelon 2013a), scoping comments, other information records, 

4 and a data-gathering site visit to Byron. NRC staff did not identify any new and significant 

5 information during the review that would result in impacts that would exceed the predicted 

6 socioeconomic impacts evaluated in the GEIS, and no additional socioeconomic NEPA issues 

7 were identified beyond those listed in Table B-1.

8 In addition, Exelon indicated in its ER (Exelon 2013a) that it has no plans to add non-outage 

9 workers during the license renewal term and that increased maintenance and inspection 

10 activities could be managed using the current workforce. Consequently, people living in the 

11 vicinity of Byron are not likely to experience any changes in socioeconomic conditions during 

12 the license renewal term beyond what is currently being experienced. Therefore, the impact of 

13 continued reactor operations during the license renewal term would not exceed the 

14 socioeconomic impacts predicted in the GEIS. For these issues, the GEIS predicted that the 

15 impacts would be SMALL for all nuclear plants.

16 4.10.2 No-Action Alternative

17 4.10.2.1 Socioeconomics

18 Not renewing the operating licenses and terminating reactor operations would have a noticeable 

19 impact on socioeconomic conditions in the communities located near Byron. The loss of jobs 

20 and income would have an immediate socioeconomic impact. Some, but not all, of the 

21 approximately 890 employees (870 Exelon and 20 long-term contract employees) would begin 

22 to leave after reactor operations are terminated; and overall tax revenue generated by plant 

23 operations would be reduced (Exelon 2013a). Exelon pays annual property taxes to a number 

24 of taxing entities within, and including, Ogle County. The Ogle County Treasurer collects 

25 Byron’s property tax payment and disperses it to the various taxing entities to partially fund their 

26 respective operating budgets. The taxing entities to which Exelon pays taxes include, but are 

27 not limited to, the Byron Forest Preserve, the Oregon Park District, the Rock Valley Community 

28 College 511, the Byron Unit 226 School District, the Byron Fire District, the Byron Library 

29 District, Ogle County, and Rockvale Township (Exelon 2013a). The loss of tax revenue could 

30 reduce or eliminate some public and educational services. Indirect employment and income 

31 generated by plant operations would also be reduced.

32 Former Byron workers and their families could leave in search of employment elsewhere. The 

33 increase in available housing along with decreased demand could cause housing prices to fall. 

34 Since the majority of employees reside in Ogle, Lee, and Winnebago Counties, socioeconomic 

35 impacts from the termination of reactor operations would be concentrated in these counties, with 

36 a corresponding reduction in purchasing activity and tax revenue in the regional economy. 
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1 Income and revenue losses from the termination of reactor operations at Byron would directly 

2 affect Ogle County and nearby communities most reliant on income from power plant 

3 operations. The impact of the job loss, however, may not be as noticeable in local communities 

4 given the amount of time required for decommissioning. The socioeconomic impacts from the 

5 termination of nuclear plant operations (which may not entirely cease until after 

6 decommissioning) would, depending on the jurisdiction, range from SMALL to LARGE.

7 4.10.2.2 Transportation

8 Traffic congestion caused by commuting workers and truck deliveries on roads in the vicinity of 

9 Byron would be reduced after power plant shutdown. Most of the reduction in traffic volume 

10 would be associated with the loss of jobs. The number of truck deliveries to Byron would be 

11 reduced until decommissioning. Traffic-related transportation impacts would be SMALL as a 

12 result of the shutdown of the nuclear power plant. 

13 4.10.3 New Nuclear Alternative

14 4.10.3.1 Socioeconomics

15 Socioeconomic impacts are defined in terms of changes to the demographic and economic 

16 characteristics and social conditions of a region. For example, the number of jobs created by 

17 the construction and operation of a power plant could affect regional employment, income, and 

18 expenditures.

19 Two types of jobs would be created by this alternative: (1) construction jobs, which are 

20 transient, short in duration, and less likely to have a long-term socioeconomic impact, and 

21 (2) power plant operations jobs, which have the greater potential for permanent, long-term 

22 socioeconomic impacts. Workforce requirements for the construction and operation of a new 

23 nuclear power plant were evaluated to measure their possible effects on current socioeconomic 

24 conditions.

25 Exelon estimated the construction workforce would peak at 3,500 workers (NRC 2008). The 

26 relative economic effect of this many workers on the local economy and tax base would vary 

27 with the greatest impacts occurring in the communities where the majority of construction 

28 workers would reside and spend their income. As a result, local communities could experience 

29 a short-term economic “boom” from increased tax revenue and income generated by 

30 construction expenditures and the increased demand for temporary (rental) housing and public 

31 as well as commercial services.

32 After construction, local communities could experience a return to preconstruction economic 

33 conditions. Based on this information and given the number of workers, socioeconomic impacts 

34 during construction in communities near an existing nuclear power plant or retired coal site 

35 could range from MODERATE to LARGE.

36 An estimated 812 workers would be required during nuclear power plant operations

37 (NRC 2008). Some Byron operations workers could transfer to the new nuclear power plant. 

38 Local communities near the new nuclear power plant would experience the economic benefits 

39 from increased tax revenue and income generated by operational expenditures and demand for 

40 housing and public as well as commercial services. The amount of property tax payments 

41 under the new nuclear alternative may also increase if additional land is required to support this 

42 alternative.

43 This alternative would also result in a loss of approximately 890 relatively high-paying jobs at 

44 Byron and a corresponding reduction in purchasing activity and revenue contributions to the 

45 regional economy. Should Byron cease operations, there would be an immediate 
Environmental Consequences and Mitigating Actions

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1 socioeconomic impact to local communities and businesses from the loss of jobs (some, but not 

2 all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, 

3 the housing market could experience increased vacancies and decreased prices if operations 

4 workers and their families move out of the region. The impact of the job loss, however, may not 

5 be noticeable in local communities given the amount of time required for decommissioning of 

6 the existing Byron facilities. Based on this information and given the number of operations 

7 workers, socioeconomic impacts during nuclear power plant operations on local communities 

8 could range from SMALL to MODERATE.

9 4.10.3.2 Transportation

10 Transportation impacts associated with construction and operation of a new nuclear power plant 

11 would consist of commuting workers and truck deliveries of construction materials to the power 

12 plant site. During periods of peak construction activity, up to 3,500 workers could be commuting 

13 daily to the construction site (NRC 2008). Workers commuting to the construction site would 

14 arrive via site access roads and the volume of traffic on nearby roads could increase 

15 substantially during shift changes. In addition to commuting workers, trucks would be 

16 transporting construction materials and equipment to the work site, thereby increasing the 

17 amount of traffic on local roads. The increase in vehicular traffic would peak during shift 

18 changes, resulting in temporary levels of service impacts and delays at intersections. Materials 

19 could also be delivered by rail or barge, depending on the location. Traffic-related 

20 transportation impacts during construction would likely range from MODERATE to LARGE.

21 Traffic-related transportation impacts on local roads would be greatly reduced after the 

22 completion of the power plant. Transportation impacts would include daily commuting by the 

23 operating workforce, equipment and materials deliveries, and the removal of commercial waste 

24 material to offsite disposal or recycling facilities by truck. Traffic on roadways would peak during 

25 shift changes, resulting in temporary levels of service impacts and delays at intersections. 

26 Overall, at the new nuclear power plant site, transportation impacts would be SMALL to 

27 MODERATE during operations.

28 4.10.4 IGCC Alternative

29 4.10.4.1 Socioeconomics

30 As explained in Section 4.10.3, two types of jobs would be created by this alternative: 

31 (1) construction jobs, which are transient, short in duration, and less likely to have a long-term 

32 socioeconomic impact, and (2) power plant operations jobs, which have the greater potential for 

33 permanent, long-term socioeconomic impacts. Workforce requirements for the construction and 

34 operation of the IGCC alternative were evaluated to measure their possible effects on current 

35 socioeconomic conditions.

36 The construction workforce could peak at 4,600 workers (DOE 2010a), if the four new units are 

37 constructed at four different locations. Fewer construction workers would be required if all units 

38 are constructed at Byron or a single existing power plant site. The relative economic effect of 

39 this many workers on the local economy and tax base would vary with the greatest impacts 

40 occurring in the communities where the majority of construction workers would reside and 

41 spend their income. As a result, local communities could experience a short-term economic 

42 “boom” from increased tax revenue and income generated by construction expenditures and the 

43 increased demand for temporary (rental) housing and public as well as commercial services.

44 After construction, local communities could experience a return to preconstruction economic 

45 conditions. Based on this information and given the number of workers, socioeconomic impacts 
Environmental Consequences and Mitigating Actions

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1 during construction in communities near an existing power plant site could range from 

2 MODERATE to LARGE.

3 An estimated 420 workers would be required during power plant operations (DOE 2010a), if the 

4 four new units are operated at four different locations. Fewer workers would be required if all 

5 four units are operated at Byron or a single existing power plant site. Local communities would 

6 experience the economic benefits from increased tax revenue and income generated by 

7 operational expenditures and demand for housing and public as well as commercial services. 

8 The amount of property tax payments under the IGCC alternative may also increase if additional 

9 land is required to support this alternative.

10 This alternative could also result in a loss of approximately 890 relatively high-paying jobs at 

11 Byron and a corresponding reduction in purchasing activity and revenue contributions to the 

12 regional economy. Should Byron cease operations, there would be an immediate 

13 socioeconomic impact to local communities and businesses from the loss of jobs (some, but not 

14 all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, 

15 the housing market could experience increased vacancies and decreased prices if operations 

16 workers and their families move out of the region. The impact of the job loss, however, may not 

17 be noticeable in local communities given the amount of time required for decommissioning of 

18 the existing Byron facilities. Based on this information and given the number of operations 

19 workers, socioeconomic impacts during IGCC power plant operations on local communities 

20 could range from SMALL to MODERATE.

21 4.10.4.2 Transportation

22 Transportation impacts associated with construction and operation of the four-unit IGCC power 

23 plants would consist of commuting workers and truck deliveries of construction materials to 

24 Byron or the existing power plant site. During periods of peak construction activity, up to 

25 4,600 workers could be commuting daily to one or more construction sites. As previously 

26 discussed, fewer workers would be commuting if all four units are constructed at Byron or a 

27 single existing power plant site. Workers commuting to the construction site would arrive via 

28 site access roads and the volume of traffic on nearby roads could increase substantially during 

29 shift changes. In addition to commuting workers, trucks would be transporting construction 

30 materials and equipment to the work site, thereby increasing the amount of traffic on local 

31 roads. The increase in vehicular traffic would peak during shift changes, resulting in temporary 

32 levels of service impacts and delays at intersections. Materials could also be delivered by rail or 

33 barge, depending on location. Traffic-related transportation impacts during construction would 

34 likely range from MODERATE to LARGE.

35 Traffic-related transportation impacts on local roads would be greatly reduced after the 

36 completion of the power plant. The estimated maximum number of operations workers 

37 commuting daily to one or more power plant sites could be 420 (DOE 2010a). Fewer workers 

38 would be commuting if all four units are operated at the same site. Frequent coal and limestone 

39 deliveries and ash removal by rail would add to the overall transportation impact. The increase 

40 in traffic on roadways would peak during shift changes, resulting in temporary levels of service 

41 impacts and delays at intersections. Onsite coal storage would make it possible to receive 

42 several trains per day at a site with rail access. If the IGCC power plant is located on navigable 

43 waters, coal and other materials could be delivered by barge. Coal and limestone delivery and 

44 ash removal via rail would cause levels of service impacts due to delays at railroad crossings. 

45 Overall, transportation impacts would be SMALL to MODERATE during IGCC power plant 

46 operations.
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1 4.10.5 NGCC Alternative

2 4.10.5.1 Socioeconomics

3 As explained in Section 4.10.3, two types of jobs would be created by this alternative: 

4 (1) construction jobs, which are transient, short in duration, and less likely to have a long-term 

5 socioeconomic impact, and (2) power plant operations jobs, which have the greater potential for 

6 permanent, long-term socioeconomic impacts. Workforce requirements for the construction and 

7 operation of the NGCC alternative were evaluated to measure their possible effects on current 

8 socioeconomic conditions.

9 The construction workforce would peak at 1,783 workers (Exelon 2013a). The relative 

10 economic effect of this many workers on the local economy and tax base would vary, with the 

11 greatest impacts occurring in the communities where the majority of construction workers would 

12 reside and spend their income. As a result, local communities near Byron or another existing 

13 power plant site could experience a short-term economic “boom” from increased tax revenue 

14 and income generated by construction expenditures and the increased demand for temporary 

15 (rental) housing and public as well as commercial services.

16 After construction, local communities could experience a return to preconstruction economic 

17 conditions. Based on this information and given the number of workers, socioeconomic impacts 

18 during construction in communities near Byron or another existing power plant site could range 

19 from MODERATE to LARGE. 

20 An estimated 94 workers would be required during power plant operations (Exelon 2013a). 

21 Local communities would experience the economic benefits from increased tax revenue and 

22 income generated by operational expenditures and demand for housing and public as well as 

23 commercial services. The amount of property tax payments under the NGCC alternative may 

24 also increase if additional land is required to support this alternative.

25 This alternative would also result in a loss of approximately 890 relatively high-paying jobs at 

26 Byron and a corresponding reduction in purchasing activity and revenue contributions to the 

27 regional economy. Should Byron cease operations, there would be an immediate 

28 socioeconomic impact to local communities and businesses from the loss of jobs (some, but not 

29 all, of the 890 employees would begin to leave), and tax payments may be reduced. In addition, 

30 the housing market could experience increased vacancies and decreased prices if operations 

31 workers and their families move out of the region. The impact of the job loss, however, may not 

32 be noticeable in local communities given the amount of time required for decommissioning of 

33 the existing Byron Station facilities. Based on this information and given the number of 

34 operations workers, socioeconomic impacts during NGCC power plant operations on local 

35 communities could range from SMALL to MODERATE.

36 4.10.5.2 Transportation

37 Transportation impacts associated with construction and operation of a five-unit NGCC power 

38 plant would consist of commuting workers and truck deliveries of construction materials to the 

39 power plant site.

40 During periods of peak construction activity, up to 1,783 workers could be commuting daily to 

41 the construction site. Workers commuting to the construction site would arrive via site access 

42 roads and the volume of traffic on nearby roads could increase substantially during shift 

43 changes. In addition to commuting workers, trucks would be transporting construction materials 

44 and equipment to the work site, thus increasing the amount of traffic on local roads. The 

45 increase in vehicular traffic would peak during shift changes, resulting in temporary levels of 

46 service impacts and delays at intersections. Pipeline construction and modification of existing 
Environmental Consequences and Mitigating Actions

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1 natural gas pipeline systems could also have a temporary impact. Materials also could be 

2 delivered by barge or rail, depending on location. Traffic-related transportation impacts during 

3 construction would likely range from MODERATE to LARGE.

4 Traffic-related transportation impacts would be greatly reduced after completing the installation 

5 of the NGCC alternative. Transportation impacts would include daily commuting by the 

6 operating workforce, equipment and materials deliveries, and the removal of commercial waste 

7 material to offsite disposal or recycling facilities by truck. The operations workforce of 

8 94 workers would likely not be noticeable relative to total traffic volumes on local roadways. 

9 Since fuel is transported by pipeline, the transportation infrastructure would experience little to 

10 no increased traffic from plant operations. Overall, given the relatively small operations 

11 workforce estimate of 94 workers, transportation impacts would be SMALL during power plant 

12 operations.

13 4.10.6 Combination Alternative (NGCC, Wind, Solar)

14 4.10.6.1 Socioeconomics

15 As explained in Section 4.10.3, two types of jobs would be created by this alternative: 

16 (1) construction jobs, which are transient, short in duration, and less likely to have a long-term 

17 socioeconomic impact, and (2) operations jobs, which have the greater potential for permanent, 

18 long-term socioeconomic impacts. Workforce requirements for the construction and operation 

19 of the NGCC, wind, and solar generation components of this combination alternative were 

20 evaluated to estimate their possible effects on current socioeconomic conditions.

21 Fewer workers would be required to construct the single NGCC unit at an existing power plant 

22 site than the full-power NGCC alternative. Installation of an estimated 3,376 wind turbines 

23 would likely be done in stages and could employ up to 931 construction workers (DOE 2010b). 

24 Additional workers would be required to install solar PV systems on existing buildings or 

25 structures at already-developed residential, commercial, or industrial sites. Similar to the wind 

26 farms, installation would likely be done in stages and could employ up to 600 construction 

27 workers (DOE 2010b). 

28 Conversely, a small number of operations workers would be needed to operate the single 

29 NGCC unit, and additional small numbers of workers would be required to maintain the wind 

30 farms and PV systems. Local communities could experience the economic benefits from 

31 increased tax revenue and income generated by operational expenditures and demand for 

32 housing and public as well as commercial services. The amount of property tax payments 

33 under the wind and solar PV components may also increase if additional land is required to 

34 support this combination alternative.

35 This combination alternative would also result in a loss of approximately 890 relatively 

36 high-paying jobs at Byron and a corresponding reduction in purchasing activity, tax payments, 

37 and revenue contributions would occur in the surrounding regional economy. Should Byron 

38 cease operations, there would be an immediate socioeconomic impact to local communities and 

39 businesses from the loss of jobs (some, but not all, of the 890 employees would begin to leave), 

40 and tax payments may be reduced. In addition, the housing market could experience increased 

41 vacancies and decreased prices if operations workers and their families move out of the region. 

42 The impact of the job loss, however, may not be noticeable in local communities given the 

43 amount of time required for decommissioning of the existing Byron Station facilities. Based on 

44 this information and given the relatively small numbers of construction and operations workers, 

45 socioeconomic impacts during construction and operations on local communities would be 

46 SMALL.
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1 4.10.6.2 Transportation

2 Transportation impacts during the construction and operation of the NGCC unit as well as the 

3 wind and solar components of this combination alternative would be less than the impacts for 

4 any of the previous alternatives discussed. This is because the construction workforce for each 

5 component and the volume of materials and equipment needing to be transported to the 

6 respective construction site would be smaller than for any one of the individual replacement 

7 power alternatives. In other words, the transportation impacts would not be concentrated as in 

8 the other alternatives, but spread out over a wider area.

9 Workers commuting to the construction site would arrive via site access roads and the volume 

10 of traffic on nearby roads could increase during shift changes. In addition to commuting 

11 workers, trucks would be transporting construction materials and equipment to the work site, 

12 thereby increasing the amount of traffic on local roads. The increase in vehicular traffic would 

13 peak during shift changes, resulting in temporary levels of service impacts and delays at 

14 intersections. Transporting heavy and oversized components on local roads could have a 

15 noticeable impact over a large area. Some components and materials could also be delivered 

16 by rail or barge, depending on location. Traffic-related transportation impacts during 

17 construction could range from SMALL to MODERATE at the NGCC power plant, wind farms 

18 and solar installations, depending on current road capacities and average daily traffic volumes.

19 During operations, transportation impacts would be less noticeable during shift changes and 

20 maintenance activities. Given the small numbers of operations workers, the levels of service 

21 traffic impacts on local roads from NGCC, wind farm, and solar PV operations would be SMALL.

22 4.10.7 Purchased Power

23 4.10.7.1 Socioeconomics

24 Purchased power from existing power generating facilities would not have any socioeconomic 

25 impact, because there would be no change in power plant operations or workforce. If the 

26 amount of purchased power exceeds the available supply, new electrical power generating 

27 facilities would be needed. Construction and operation of a new electrical power generating 

28 facility to supply purchased power could cause noticeable socioeconomic impacts in the 

29 communities located near the new facility. The intensity of the impact would depend on the 

30 number of workers required to build and operate the new electrical power generating facility and 

31 the amount of increased demand for housing and public services.

32 Whether or not there would be a socioeconomic impact would depend on whether a new 

33 electrical power generating facility was needed to supply purchased power. If a new power 

34 generating facility is needed, socioeconomic impacts would range anywhere from SMALL to 

35 LARGE.

36 4.10.7.2 Transportation

37 Similarly, purchased power from existing power generating facilities would also not have any 

38 transportation impact, because there would be no change in power plant operations or 

39 workforce. Construction and operation of a new electrical power generating facility could cause 

40 noticeable transportation impacts depending on the number of workers and truck deliveries 

41 required to build and operate the new electrical power generating facility. Traffic volumes could 

42 increase noticeably on local roads during shift changes.

43 Whether or not there would be a transportation impact would depend on whether a new 

44 electrical power generating facility was needed to supply purchased power. If a new power 
Environmental Consequences and Mitigating Actions

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1 generating facility is needed, transportation impacts would range anywhere from SMALL to 

2 LARGE.

3 4.11 Human Health

4 This section describes the potential impacts of the proposed action (license renewal) and 

5 alternatives to the proposed action on human health resources. 

6 4.11.1 Proposed Action

7 The human health issues applicable to Byron are discussed below and are listed in Table 4–13 

8 for Category 1, Category 2, and uncategorized issues. Table B-1 of Appendix B to Subpart A of 

9 10 CFR Part 51 contains more information on these issues.

10 Table 4–13. Human Health Issues

Issue GEIS Section Category

Radiation exposures to the public 4.9.1.1.1 1

Radiation exposures to plant workers 4.9.1.1.1 1

Human health impact from chemicals 4.9.1.1.2 1

Microbiological hazards to the public (plants with cooling ponds or 

canals or cooling towers that discharge to a river) 4.9.1.1.3 2 

Microbiological hazards to plant workers 4.9.1.1.3 1

Chronic effects of electromagnetic fields (EMFs)(a) 4.9.1.1.4 N/A(b)

Physical occupational hazards 4.9.1.1.5 1

Electric shock hazards(a) 4.9.1.1.5 2

(a) This issue applies only to the inscope portion of electric power transmission lines, which are defined as 

transmission lines that connect the nuclear power plant to the substation where electricity is fed into the regional 

power distribution system and transmission lines that supply power to the nuclear plant from the grid.

(b) N/A (not applicable) The categorization and impact finding definition does not apply to this issue

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51 (NRC 2013a)

11 4.11.1.1 Normal Operating Conditions

12 Generic Human Health Issues (Category 1)

13 The NRC staff did not identify any new and significant information during its review of Exelon’s 

14 ER (Exelon 2013a), the site audit, or the scoping process for the Category 1 issues listed in 

15 Table 4–13. Therefore, there are no impacts related to these issues beyond those discussed in 

16 the GEIS. For these Category 1 issues, the GEIS concluded that the impacts are SMALL.

17 Chronic Effects of Electromagnetic Fields (EMFs)

18 In the GEIS (NRC 2013a), the chronic effects of 60-Hz electromagnetic fields (EMFs) from 

19 power lines were not designated as Category 1 or 2 and will not be until a scientific consensus 

20 is reached on the health implications of these fields.
Environmental Consequences and Mitigating Actions

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1 The potential for chronic effects from these fields continues to be studied and is not known at 

2 this time. The National Institute of Environmental Health Sciences (NIEHS) directs related 

3 research through the U.S. Department of Energy (DOE).

4 The report by NIEHS (NIEHS 1999) contains the following conclusion:

5 The NIEHS concludes that ELF-EMF (extremely low frequency-electromagnetic 

6 field) exposure cannot be recognized as entirely safe because of weak scientific 

7 evidence that exposure may pose a leukemia hazard. In our opinion, this finding 

8 is insufficient to warrant aggressive regulatory concern. However, because 

9 virtually everyone in the United States uses electricity and therefore is routinely 

10 exposed to ELF-EMF, passive regulatory action is warranted such as continued 

11 emphasis on educating both the public and the regulated community on means 

12 aimed at reducing exposures. The NIEHS does not believe that other cancers or 

13 non-cancer health outcomes provide sufficient evidence of a risk to currently 

14 warrant concern.

15 This statement is not sufficient to cause the NRC staff to change its position with respect to the 

16 chronic effects of EMFs. The NRC staff considers the GEIS finding of “UNCERTAIN” still 

17 appropriate and will continue to follow developments on this issue.

18 Site-Specific Human Health Issues (Category 2)

19 Microbiological Hazards to the Public

20 In the GEIS (NRC 2013a), the NRC staff determined that effects of thermophilic microorganisms 

21 on the public for plants using cooling ponds, lakes, or canals or cooling towers that discharge to 

22 a river is a Category 2 issue (see Table 4–12) that requires site-specific evaluation during each 

23 license renewal review. 

24 In order to determine whether the continued operations of Byron could promote increased 

25 growth of thermophilic microorganisms, and thus have an adverse effect on the public, the NRC 

26 staff considered several factors: the thermophilic microorganisms of concern, Byron’s thermal 

27 effluent characteristics, Exelon’s chlorination procedures, recreational Rock River use in the 

28 vicinity of Byron, and input from the Illinois Department of Public Health (IDPH).

29 Thermophilic Microorganisms of Concern

30 Section 3.11.3 describes the thermophilic microorganisms that the GEIS identified to be of 

31 potential concern at nuclear power plants and summarizes data from the Centers for Disease 

32 Control and Prevention (CDC) on the prevalence of waterborne diseases associated with these 

33 microorganisms that have been linked to recreational water use in the past 10 available data 

34 years (1999 through 2008). CDC data indicate that no outbreaks or cases of waterborne 

35 Salmonella or Pseudomonas aeruginosa infection from recreational waters have occurred in the 

36 United States during this timeframe. Shigella and Naegleria fowleri infections linked to 

37 exposure in recreational waters were rarely reported, and none of the reported cases occurred 

38 in Illinois. Public exposure to aerosolized Legionella from nuclear plant operations is generally 

39 not a concern because such exposure would be confined to a small area of the site to which the 

40 public would not have access. Based on the information presented in Section 3.11.3, the 

41 thermophilic organisms most likely to be of potential concern at Byron are Shigella and 

42 N. fowleri. 

43 Byron Thermal Effluent Characteristics

44 Byron discharges cooling tower blowdown to the Rock River at an average rate of 900 L/s 

45 (14,000 gpm) (Exelon 2013a). Sections 3.1.3 and 3.5.1 describe the cooling system and 

46 surface water characteristics, respectively.
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1 The Illinois Administrative Code (IAC) Title 35, Environmental Protection, Section 302, “Water 

2 Quality Standards,” stipulates that for thermal effluents, the maximum temperature rise shall not 

3 exceed 2.8 °C (5 °F) above natural receiving water body temperatures and that the water 

4 temperature at representative locations in the main river shall at no time exceed 33.7°C (93 °F) 

5 from April through November and 17.7 °C (63°F) in other months (35 IAC 302.211). Special 

6 Condition 12 of Byron’s NPDES permit (IEPA 2011) requires Exelon to perform daily 

7 calculations to demonstrate compliance with the thermal water quality standard during times 

8 when Rock River flow is less than 67,944 L/s (1,076,900 gpm) or the temperature difference 

9 between the main river temperature and the water quality standard is less than 3°F (1.6°C). 

10 In recent years, the highest daily blowdown temperature that Exelon reported was 39.4°C 

11 (103 °F) in July 2012 (Exelon 2013b). This temperature was recorded during drought conditions 

12 in Illinois. Previously, the highest temperature had been 36°C (97 °F) in August 2009 

13 (Exelon 2013a). The July 2012 maximum temperature is below the optimum growth 

14 temperature for the microorganisms of concern. At this temperature, Shigella could persist but 

15 would be unlikely to experience enhanced growth or survival from the thermal addition of 

16 cooling tower blowdown to the river. N. fowleri prefers much higher temperatures for optimum 

17 growth (46 °C (115°F)). N. fowleri has been isolated from thermally altered waters surrounding 

18 power plant discharges at temperatures ranging from 35 to 41 °C (95 to 105.8 °F); however, 

19 because the IAC normally limits discharge temperatures to 33.7°C (93 °F), the species is 

20 unlikely to be present in the water.

21 Additionally, the IAC prohibits the area and volume of thermal mixing from being more than 

22 25 percent of the cross-sectional area or volume of stream flow (35 IAC 302.102). The Illinois 

23 Environmental Protection Agency (IEPA) has determined that Byron meets this criterion, as 

24 stated in Special Condition 3 of Byron’s NPDES permit (IEPA 2011). Thus, the IAC’s thermal 

25 mixing limitations effectively minimize the area and volume over which microorganisms could 

26 experience enhanced growth or survival.

27 Byron Chlorination Procedures

28 Chlorine is an effective disinfectant for water containing the microorganisms of concern. EPA

29 (1999a) reports that chlorination at concentrations of 1 to 2 milligrams per liter (mg/L) (1 to 

30 2 parts per million (ppm)) in water at a pH of 6.0 to 8.0 can effectively eliminate health hazards 

31 caused by bacteria, including Shigella. The CDC (2013) reports that chlorine at a concentration 

32 of 1 ppm (1 mg/L) added to 77 °F (25°C) clear water at a pH of 7.5 will reduce the number of 

33 viable Naegleria fowleri trophozoites by 99.99 percent in 12 minutes. 

34 Exelon chlorinates Rock River water, which is then used in Byron’s three cooling and auxiliary 

35 water systems. Sodium hypochlorite and sodium bromide at target concentrations of 0.2 and 

36 0.5 ppm are injected into each unit’s circulating water system for 2 hours per day per unit during 

37 operation. The nonessential service water system is chlorinated by continuously injecting 

38 sodium hypochlorite at a concentration of 0.05 to 0.2 ppm. The essential service water (SX)

39 system is also continuously chlorinated with sodium hypochlorite at a concentration of 0.05 to 

40 0.2 ppm. Sodium bisulfate is added to water to eliminate any residual biocide concentration 

41 prior to returning water to the Rock River (Exelon 2013b). Although Exelon chlorinates station 

42 water at lower concentrations than those indicated by EPA and the CDC as most effectively 

43 eliminating the microorganisms of concern, chlorination of the system is likely to prevent some 

44 increased growth and survival of microorganisms that might otherwise result from operation of 

45 Byron.
Environmental Consequences and Mitigating Actions

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1 Recreational Rock River Use in the Vicinity of Byron

2 As discussed above, Byron’s thermal mixing zone is relatively small. Thus, the highest risk of 

3 exposure to elevated levels of thermophilic microorganisms, if present, would likely be within the 

4 restricted area. Additionally, the majority of land adjacent to the Rock River in the vicinity of 

5 Byron is private and zoned for agricultural uses (OCPZD 2013). Thus, because public access 

6 to waters that are thermally affected by Byron operations is limited, exposure of the public to 

7 elevated levels of thermophilic microorganisms is unlikely. Additionally, the IAC prohibits mixing

8 “in water adjacent to bathing beaches, bank fishing areas, boat ramps or dockages or any other 

9 public access area.” Thus, any changes in surrounding land use during the proposed license 

10 renewal term would continue to limit public exposure to thermally altered waters.

11 Illinois Department of Public Health Review

12 The Environmental Standard Review Plan for license renewal (NRC 2013c) directs NRC staff to 

13 consult with the state public health department—in this case, the IDPH—regarding concerns 

14 about the potential for waterborne disease outbreaks associated with license renewal. 

15 Appendix E of the ER (Exelon 2013a) includes copies of correspondence between Exelon and 

16 IDPH regarding this issue. In a January 2013 letter to IDPH, Exelon (2013d) provided a brief 

17 assessment that concluded that the license renewal “would not contribute to any increase in 

18 adverse effects on public health from exposure to N. fowIeri or any other thermophilic pathogen 

19 in the Rock River.” The IDPH (2013) responded in a March 2013 letter and indicated that its 

20 staff does not have the expertise necessary to adequately evaluate Exelon’s assessment. 

21 Accordingly, the NRC did not separately contact the IDPH during its license renewal review.

22 Conclusion

23 The thermophilic microorganisms Shigella and Naegleria fowleri have been linked to waterborne 

24 outbreaks in recreational waters within the United States. However, based on these 

25 microorganisms’ temperature tolerances, N. fowleri is unlikely to be present in the vicinity of 

26 Byron, and thermal discharges during the proposed license renewal term would only be 

27 expected to minimally enhance the survival of Shigella spp. Exelon’s chlorination procedures 

28 and the small thermal mixing zone make the exposure of recreational Rock River users to 

29 elevated levels of thermophilic microorganisms unlikely. The NRC staff concludes that the 

30 impacts of thermophilic microorganisms on the public are SMALL for Byron license renewal.

31 Electric shock hazards

32 Based on the GEIS, the Commission found that electric shock resulting from direct access to 

33 energized conductors or from induced charges in metallic structures has not been found to be a 

34 problem at most operating plants and generally is not expected to be a problem during the 

35 license renewal term. However, a site-specific review is required to determine the significance 

36 of the electric shock potential along the portions of the transmission lines that are within the 

37 scope of this SEIS.

38 As discussed in Section 3.11.4, Exelon performed an evaluation of Byron’s transmission lines to 

39 determine whether the lines conform to the National Electrical Safety Code® (NESC®) criteria 

40 for induced electric shock. The Exelon evaluation concluded that none of its transmission lines 

41 exceeded the NESC criteria.

42 Because Byron’s transmission lines conform to the NESC criteria during its current license term 

43 and is expected to continue to conform to this standard during the license renewal term, the 

44 NRC staff concludes that the potential impacts from acute electric shock during the license 

45 renewal term would be SMALL.
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1 4.11.1.2 Environmental Impacts of Postulated Accidents

2 This section describes the environmental impacts from postulated accidents that Byron might 

3 experience during the period of extended operation. The term “accident” refers to any 

4 unintentional event outside the normal plant operational envelope that results in a release or the 

5 potential for release of radioactive materials into the environment. The two classes of 

6 postulated accidents listed in Table 4–14 are contained in Table B-1 of Appendix B to Subpart A 

7 of 10 CFR Part 51 and are evaluated in detail in the GEIS. These two classes of accidents are

8 DBAs and severe accidents. 

9 Table 4–14. Issues Related to Postulated Accidents

Issue GEIS Section Category

DBAs 4.9.1.2 1

Severe accidents 4.9.1.2 2

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51

10 Design-Basis Accidents

11 In order to receive U.S. Nuclear Regulatory Commission (NRC) approval to operate a nuclear 

12 power facility, an applicant for an initial operating license must submit a Safety Analysis Report 

13 (SAR) as part of its application. The SAR presents the design criteria and design information for 

14 the proposed reactor and comprehensive data on the proposed site. The SAR also discusses 

15 various hypothetical accident situations and the safety features that are provided to prevent and 

16 mitigate accidents. The NRC staff reviews the application to determine whether the plant 

17 design meets the Commission’s regulations and requirements and includes, in part, the nuclear 

18 plant design and its anticipated response to an accident.

19 Design-basis accidents are those accidents that both the applicant and the NRC staff evaluate 

20 to ensure that the plant can withstand normal and abnormal transients and a broad spectrum of 

21 postulated accidents, without undue hazard to the health and safety of the public. Many of 

22 these postulated accidents are not expected to occur during the life of the plant, but are 

23 evaluated to establish the design basis for the preventive and mitigative safety systems of the 

24 nuclear power plant. Parts 50 and 100 of 10 CFR describe the acceptance criteria for DBAs.

25 The environmental impacts of DBAs are evaluated during the initial licensing process, and the 

26 ability of the plant to withstand these accidents is demonstrated to be acceptable before 

27 issuance of the operating license. The results of these evaluations are found in licensee 

28 documentation such as the applicant’s final safety analysis report, the safety evaluation report, 

29 the final environmental statement (FES), and Section 5.1 of this SEIS. A licensee is required to 

30 maintain the acceptable design and performance criteria throughout the life of the plant, 

31 including any extended-life operation. The consequences for these events are evaluated for the 

32 hypothetical maximum exposed individual; as such, changes in the plant environment will not 

33 affect these evaluations. Because of the requirements that continuous acceptability of the 

34 consequences and aging management programs be in effect for the period of extended 

35 operation, the environmental impacts as calculated for DBAs should not differ significantly from 

36 initial licensing assessments over the life of the plant, including the period of extended 

37 operation. Accordingly, the design of the plant relative to DBAs during the period of extended 

38 operation is considered to remain acceptable, and the environmental impacts of those accidents 

39 were not examined further in the GEIS. 
Environmental Consequences and Mitigating Actions

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1 The Commission has determined that the environmental impacts of DBAs are of SMALL 

2 significance for all plants because the plants were designed to successfully withstand these 

3 accidents. Therefore, for the purposes of license renewal, DBAs are designated as a 

4 Category 1 issue. The early resolution of the DBAs makes them a part of the current licensing 

5 basis of the plant; the current licensing basis of the plant is to be maintained by the licensee 

6 under its current license and, therefore, under the provisions of 10 CFR 54.30, is not subject to 

7 review under license renewal. 

8 No new and significant information related to DBAs was identified during the review of the Byron

9 ER (Exelon 2013a), site audit, the scoping process, or evaluation of other available information. 

10 Therefore, there are no impacts related to these issues beyond those discussed in the GEIS. 

11 Severe Accidents

12 Severe nuclear accidents are those that are more severe than DBAs because they could result 

13 in substantial damage to the reactor core, whether or not there are serious offsite 

14 consequences. In the GEIS, the NRC staff assessed the effects of severe accidents during the 

15 period of extended operation, using the results of existing analyses and site-specific information 

16 to conservatively predict the environmental impacts of severe accidents for each plant during 

17 the period of extended operation.

18 Severe accidents initiated by external phenomena such as tornadoes, floods, earthquakes, 

19 fires, and sabotage have not traditionally been discussed in quantitative terms in FESs and 

20 were not specifically considered for the Byron site in the GEIS (NRC 1996). However, the GEIS 

21 did evaluate existing impact assessments performed by NRC and by the industry at 44 nuclear 

22 plants in the United States and concluded that the risk from beyond-design-basis earthquakes 

23 at existing nuclear power plants is SMALL. The GEIS for license renewal performed a 

24 discretionary analysis of terrorist acts in connection with license renewal, and concluded that the 

25 core damage and radiological release from such acts would be no worse than the damage and 

26 release expected from internally initiated events. In the GEIS, the Commission concludes that 

27 the risk from sabotage and beyond-design-basis earthquakes at existing nuclear power plants is 

28 small and additionally, that the risks from other external events are adequately addressed by a 

29 generic consideration of internally initiated severe accidents (NRC 1996, 2013a).

30 Based on information in the GEIS, the staff found the following to be true:

31 The probability weighted consequences of atmospheric releases, fallout onto 

32 open bodies of water, releases to ground water, and societal and economic 

33 impacts from severe accidents are small for all plants. However, alternatives to 

34 mitigate severe accidents must be considered for all plants that have not 

35 considered such alternatives.

36 The NRC staff identified no new and significant information related to postulated accidents

37 during the review of Exelon’s ER for Byron (Exelon 2013a), the site audit, the scoping process, 

38 or evaluation of other available information. Therefore, there are no impacts related to these 

39 issues beyond those discussed in the GEIS. However, in accordance with 

40 10 CFR 51.53(c)(3)(ii)(L), the staff has reviewed severe accident mitigation alternatives 

41 (SAMAs) for Byron. The results of the review are discussed in Section 5.3.

42 Severe Accident Mitigation Alternatives

43 Section 51.53(c)(3)(ii)(L) requires that license renewal applicants consider alternatives to 

44 mitigate severe accidents if the staff has not previously evaluated SAMAs for the applicant’s 

45 plant in an environmental impact statement (EIS) or related supplement or in an environmental 

46 assessment (EA). The purpose of this consideration is to ensure that plant changes 

47 (i.e., hardware, procedures, and training) with the potential for improving severe accident safety 
Environmental Consequences and Mitigating Actions

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1 performance are identified and evaluated. SAMAs have not been previously considered for

2 Byron; therefore, the remainder of this section addresses those alternatives. 

3 Overview of SAMA Process

4 This section presents a summary of the SAMA evaluation for Byron conducted by Exelon and 

5 the NRC staff’s review of that evaluation. The NRC staff performed its review with contract 

6 assistance from Pacific Northwest National Laboratory. The NRC staff’s review is available in 

7 full in Appendix F; the full Exelon SAMA evaluation is available in Exelon’s ER.

8 The SAMA evaluation for Byron was conducted with a four-step approach. In the first step, 

9 Exelon quantified the level of risk associated with potential reactor accidents using the 

10 plant-specific probabilistic risk assessment (PRA) and other risk models.

11 In the second step, Exelon examined the major risk contributors and identified possible ways 

12 (SAMAs) of reducing that risk. Common ways of reducing risk are changes to components, 

13 systems, procedures, and training. Exelon identified 30 potential SAMAs for Byron. Exelon 

14 performed an initial screening to determine if any SAMAs could be eliminated because they are 

15 not applicable to Byron due to design differences, they have already been implemented at 

16 Byron or their intent is achieved by other means, or they have estimated implementation costs 

17 that would exceed the dollar value associated with completely eliminating all severe accident

18 risk at Byron related to power generation operations. Three SAMAs were eliminated based on 

19 this screening, leaving 27 for further evaluation. One additional candidate SAMA was also 

20 further evaluated after accounting for analysis uncertainties.

21 In the third step, Exelon estimated the benefits and the costs associated with each of the 

22 SAMAs. Estimates were made of how much each SAMA could reduce risk. Those estimates 

23 were developed in terms of dollars in accordance with NRC guidance for performing regulatory 

24 analyses (NRC 1997). The cost of implementing the proposed SAMAs was also estimated.

25 In the fourth step, the costs and benefits of each of the remaining SAMAs were compared to 

26 determine whether the SAMA was cost beneficial, meaning the benefits of the SAMA were 

27 greater than the cost (a positive cost benefit). Exelon concluded in its ER that several of the 

28 SAMAs evaluated are potentially cost beneficial (Exelon 2013a). In response to NRC staff 

29 inquiries regarding estimated benefits for certain SAMAs and lower cost alternatives, 

30 two additional potentially cost-beneficial SAMAs were identified (Exelon 2014).

31 Finally, the potentially cost-beneficial SAMAs are evaluated to determine if they are in the scope 

32 of license renewal, (i.e., they are subject to aging management). This evaluation considers 

33 whether the structures, systems, and components (SSCs) associated with these SAMAs: 

34 (1) perform their intended function without moving parts or without a change in configuration or 

35 properties and (2) are subject to replacement based on qualified life or specified time period.

36 The potentially cost-beneficial SAMAs identified for Byron do not relate to adequately managing 

37 the effects of aging during the period of extended operation; therefore, they need not be 

38 implemented as part of license renewal in accordance with 10 CFR Part 54, “Requirements for 

39 renewal of operating licenses for nuclear power plants.” Byron’s SAMA analyses and the NRC’s 

40 review are discussed in more detail below.

41 Estimate of Risk

42 Exelon submitted an assessment of SAMAs for Byron as part of its ER (Exelon 2013). This 

43 assessment was based on the most recent Byron PRA available at that time, a plant-specific 

44 offsite consequence analysis performed using the MELCOR Accident Consequence Code 

45 System 2 computer program, and insights from the Byron Individual Plant Examination (IPE) 
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1 (ComEd 1994, 1997) and Individual Plant Examination of External Events (IPEEE) 

2 (ComEd 1996).

3 The scope of the Level 1 PRA model includes both internal events and a limited fire PRA. The 

4 fire PRA is not fully integrated with the most recent internal events model and is an interim 

5 implementation of NUREG–6850 (EPRI and NRC 2005). Hence, Exelon performed a separate 

6 assessment of the risk (and risk reduction) for internal and fire events.

7 The baseline core damage frequency (CDF) for the purpose of the SAMA evaluation is 

approximately 4.0×10−5 per year for Unit 1 and 3.8×10−5 8 per year for Unit 2 for internal events 

(including internal flooding events). The total fire CDF for Unit 1 is approximately 5.4×10−5 9 per 

10 year. The Unit 2 fire CDF was not reported or used since the Unit 2 fire model had not been 

11 developed to the same degree as the Unit 1 model. Exelon accounted for the potential risk 

12 reduction benefits associated with internal events by quantifying the benefits using the internal 

13 events model. For internal event-related SAMAs, Exelon accounted for the potential risk 

14 reduction benefits associated with external events (e.g., seismic and fire events) by multiplying 

15 the estimated benefits for internal events by a factor of 2.6. For fire-related SAMAs, Exelon 

16 separately estimated the risk reduction benefits using the fire risk model. The breakdown of 

17 CDF by initiating event for Byron is provided in Table 4–15 for internal events.

18 Table 4–15. Byron Core Damage Frequency for Internal Events

Initiating Event Unit 1 CDF

(per year)

Unit 1

Percent CDF

Contribution

Unit 2 CDF

(per year)

Unit 2 Percent 

CDF

Contribution 

Loss of Essential Service Water (SX) 1.8×10−5 46 1.7×10−5 45

Loss of Component Cooling Water 

(CCW) 8.3×10−6 21 8.1×10−6 21

Internal Flooding 5.6×10−6 14 5.8×10−6 15

Loss of Auxiliary Power (AP) 2.4×10−6 6 1.8×10−6 5

Small Loss-of-Coolant Accident 

(LOCA) 1.6×10−6 4 1.5×10−6 4 

Other Initiating Events 1.6×10−6 4 1.6×10−6 4

Steam Generator Tube Rupture 

(SGTR) 1.2×10−6 3 1.5×10−6 4 

General Transient and Loss of Main 

Feedwater (LMFW) 7.9×10−7 2 6.8×10−7 2 

Total (Internal Events)(a) 4.0×10−5 100 3.8×10−5 100

(a) Column totals may be different due to round off.

19 As shown in these tables, internal event CDF is dominated by loss of SX, loss of component 

20 cooling water (CCW), and internal flooding for both units.

21 Exelon estimated the dose to the population within 50 mi (80 km) of the Byron site to be 

22 approximately 0.355 person-sievert (Sv) (35.5 person-rem) per year (Exelon 2013a) for internal 

23 events. The breakdown of the total population dose by containment release mode is 

24 summarized in Table 4–16. Containment overpressure accidents, interfacing-systems 

25 loss-of-coolant accident (ISLOCA), and steam generator tube rupture (SGTR) are the dominant 

26 contributors to population dose risk from internal events.
Environmental Consequences and Mitigating Actions

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1 Table 4–16. Breakdown of Population Dose and Offsite Economic Cost by Containment 

Release Mode (a) 2 

Containment Release Mode

Population Dose

(person-rem(b)

per year)

Percent 

Contribution

Offsite 

Economic 

Cost

($/yr)

Percent 

Contribution

Containment overpressure (late) 28.3 80 222,700 88

ISLOCA 4.42 12 11,800 5

Steam generator tube rupture 2.16 6 17,600 7

Containment isolation failure 0.34 <1 1,660 <1

Containment intact 0.13 <1 120 <1

Early containment failure 0.09 <1 580 <1

Basemat melt-through (late) 0.02 <1 40 <1

Total (c) 35.5 100 255,000 100

(a) Values in table derived from Table F.3-9 of the ER.

(b) 1 person-rem = 0.01 person-Sv.

(c) Column totals may be different due to round off.

3 The NRC staff has reviewed Exelon’s data and evaluation methods and concludes that the 

4 quality of the risk analyses is adequate to support an assessment of the risk reduction potential 

5 for candidate SAMAs. Accordingly, the staff based its assessment of offsite risk on the CDFs 

6 and offsite doses reported by Exelon.

7 Potential Plant Improvements

8 Once the dominant contributors to plant risk were identified, Exelon searched for ways to reduce 

9 that risk. In identifying and evaluating potential SAMAs, Exelon considered insights from the 

10 plant-specific PRA and SAMA analyses performed for other operating plants that have 

11 submitted license renewal applications. This search included reviewing insights from the 

12 plant-specific risk studies, considering insights from the Byron PRA Group, and reviewing plant 

13 improvements considered in the IPE, IPEEE, and previous SAMA analyses. Exelon identified 

14 30 potential risk-reducing improvements (SAMAs) to plant components, systems, procedures 

15 and training.

16 Exelon removed three of the SAMAs from further consideration because they are not applicable 

17 to Byron due to design differences, they have already been implemented at Byron or their intent 

18 is achieved by other means, or they have estimated implementation costs that would exceed the 

19 dollar value associated with completely eliminating all severe accident risk at Byron related to 

20 power generation operations. One additional candidate SAMA was further evaluated after 

21 accounting for analysis uncertainties. A detailed cost-benefit analysis was performed for each 

22 of the remaining 28 SAMAs.

23 The NRC staff concludes that Exelon used a systematic and comprehensive process for

24 identifying potential plant improvements for Byron, and that the set of potential plant

25 improvements identified by Exelon is reasonably comprehensive and, therefore, acceptable.
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1 Cost-Benefit Comparison

2 The cost benefit analysis performed by Exelon was based primarily on NUREG/BR–0184 

3 (NRC 1997) and was executed consistent with this guidance. NUREG/BR–0058 has recently 

4 been revised to reflect the agency’s revised policy on discount rates. Revision 4 of

5 NUREG/BR–0058 states that two sets of estimates should be developed—one at 3 percent and

6 one at 7 percent (NRC 2004). Exelon provided both sets of estimates (Exelon 2013, 2014) and 

7 based its decisions on potentially cost-beneficial SAMAs on these values.

8 Exelon identified 10 potentially cost-beneficial SAMAs in the baseline analysis contained in its

9 ER. The potentially cost-beneficial SAMAs are:

10 • SAMA 3 – Auto Start of Standby SX Pump;

11 • SAMA 5 – Modify the Startup Feedwater Pump to Start Using the AMSAC SG 

12 Low-Low-Low Level Signal to Mitigate AFW Failure; 

13 • SAMA 9 – Install Flow Restrictors in Fire Protection Pipes;

14 • SAMA 10 – Alter Ductwork Between the Aux BLDG Room and the SX Pump 

15 Room;

16 • SAMA 13 – Alternate AFW Cooling with Seal Protection;

17 • SAMA 15 – Resolve Regulatory Issues and Complete Implementation of the 

18 Inter Unit AFW Cross-tie;

19 • SAMA 25 – Install a Filtered Containment Vent;

20 • SAMA 26 – DMS Using a Dedicated Generator, Self Cooled Charging Pump, 

21 and a Portable AFW Pump;

22 • SAMA 27 – Protect RHR,SI and CVCS Cubicle Cooling Fan Cables in Fire 

23 Zone 11.3-0; and

24 • SAMA 31 – Protect Cables for 2AF013A, B, and D in the AUX Building 

25 General Area, Elevation 426′.

26 Exelon performed additional analyses to evaluate the impact of parameter choices and 

27 uncertainties on the results of the SAMA assessment (Exelon 2013, 2014). If the benefits are

28 increased by a factor of 2.53 to account for uncertainties, 10 additional SAMA candidates were

29 determined to be potentially cost beneficial:

30 • SAMA 1 – Install Diesel Driven SX Pump in a New Dedicated Building;

31 • SAMA 2 – Replace the Positive Displacement Pump with a Self-Cooled, Auto 

32 Start Pump;

33 • SAMA 4 – Install “No Leak” Seals;

34 • SAMA 7 – Establish Flow to the RH HX on RH Pump Start;

35 • SAMA 8 – Install Kill Switches for the Fire Protection Pumps in the MCR;

36 • SAMA 11 – Implement DMS;

37 • SAMA 16 – Install High Flow Sensors on the Non-Essential Service Water 

38 System;

39 • SAMA 19 – Replace MOVs in the RHR Discharge Line with Valves that can 

40 Isolate an ISLOCA Event;
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1 • SAMA 28 – Install Fire Barriers Around MCC 134X; and

2 • SAMA 30 – Protect AFW Cables in the AUX Building General Area, 

3 Elevation 383′.

4 Exelon stated in its ER that 18 of the SAMAs (SAMAs 2, 3, 5, 7, 8, 9, 10, 11, 13, 15, 16, 19, 25, 

5 26, 27, 28, 30, and 31) determined to be cost beneficial in its ER baseline and uncertainty 

6 evaluations have been submitted to the Byron Plant Health Committee for further 

7 implementation consideration (Exelon 2013a). Exelon stated that installation of SAMA 4 at 

8 Byron is planned, that contract awards have already been made to install the new reactor

9 coolant pump seals, and that engineering and analysis work necessary to install the new seals 

10 has already begun (Exelon 2014). Exelon also stated in its ER that SAMA 11 may be fully or 

11 partially implemented at Byron for other purposes, which, if fully implemented along with 

12 SAMA 15 (which is currently being implemented), would result in SAMA 1 no longer being cost

13 beneficial. Since full implementation of SAMA 11 in conjunction with SAMA 15 would result in 

14 SAMA 1 not being cost beneficial, the NRC staff concludes that the applicant should consider 

15 SAMA 1 for further evaluation, depending on the degree of implementation of SAMA 11.

16 The NRC staff concludes that, with the exception of the potentially cost-beneficial SAMAs 

17 discussed above, the costs of the SAMAs evaluated would be higher than the associated 

18 benefits when they are considered independently.

19 Conclusions

20 The NRC staff reviewed Exelon’s analysis and concludes that the methods used and the

21 implementation of those methods were sound. The treatment of SAMA benefits and costs

22 support the general conclusion that the SAMA evaluations performed by Exelon are reasonable 

23 and sufficient for the license renewal submittal.

24 Based on its review of the SAMA analysis, the NRC staff finds Exelon’s identification of areas in 

25 which risk can be further reduced in a cost-beneficial manner through the implementation of all 

26 or a subset of potentially cost-beneficial SAMAs to be acceptable. Given the potential for 

27 cost-beneficial risk reduction, the staff considers that further evaluation of these SAMAs by

28 Exelon is warranted. Additionally, the NRC staff evaluated the identified potentially 

29 cost-beneficial SAMAs to determine if they are in the scope of license renewal, (i.e., they are 

30 subject to aging management). This evaluation considers whether the SSCs associated with 

31 these SAMAs: (1) perform their intended function without moving parts or without a change in 

32 configuration or properties and (2) are not subject to replacement based on qualified life or 

33 specified time period. The NRC staff determined that these SAMAs do not relate to adequately 

34 managing the effects of aging during the period of extended operation. Therefore, they need 

35 not be implemented as part of the license renewal pursuant to 10 CFR Part 54.

36 4.11.2 No-Action Alternative

37 Human health risks would be smaller following plant shutdown. The two reactor units, which are

38 currently operating within regulatory limits, would emit less radioactive gaseous, liquid, and solid 

39 material to the environment. In addition, following shutdown, the variety of potential accidents at 

40 the plant (radiological or industrial) would be reduced to a limited set associated with shutdown 

41 events and fuel handling and storage. In Section 4.11.1, the NRC staff concluded that the

42 impacts of continued plant operation on human health would be SMALL, except for “Chronic 

43 effects of electromagnetic fields (EMFs),” for which the impacts are UNCERTAIN. In 

44 Section 4.11.1.2, the NRC staff concluded that the impacts of accidents during operation are

45 SMALL. Therefore, as radioactive emissions to the environment decrease, and as the likelihood 
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1 and types of accidents decrease following shutdown, the NRC staff concludes that the risk to 

2 human health following plant shutdown would be SMALL.

3 4.11.3 New Nuclear Alternative

4 Impacts on human health from construction of two new nuclear units would be similar to impacts 

5 associated with the construction of any major industrial facility. Compliance with worker 

6 protection rules would control those impacts on workers at acceptable levels. Impacts from 

7 construction on the general public would be minimal since limiting active construction area 

8 access to authorized individuals is expected. Impacts on human health from the construction of 

9 two new nuclear units would be SMALL.

10 The human health effects from the operation of two new nuclear power plants would be similar 

11 to those of the existing Byron. As presented in Section 4.11.1.1, impacts on human health from 

12 the operation of Byron would be SMALL, except for “Chronic effects of electromagnetic fields 

13 (EMFs),” for which the impacts are UNCERTAIN. Therefore, the impacts on human health from 

14 the operation of two new nuclear plants would be SMALL.

15 4.11.4 IGCC Alternative

16 Impacts on workers are expected to be similar to those experienced during construction of any 

17 major industrial facility. Impacts from construction of combustion-based renewable energy 

18 facilities are expected to be the same as those for construction of fossil fuel facilities. 

19 Construction would increase traffic on local roads, which could affect the health of the general 

20 public. Human health impacts would be the same for all facilities whether located on greenfield 

21 sites or at an existing nuclear plant. Personal protective equipment, training, and engineered 

22 barriers would protect the workforce (NRC 2013a). Therefore, the impacts on human health 

23 from the construction of an IGCC facility would be SMALL.

24 The IGCC alternative introduces worker risks from coal and limestone mining, worker and public 

25 risk from coal and lime/limestone transportation, worker and public risk from disposal of 

26 coal-combustion waste, and public risk from inhalation of stack emissions. In addition, human 

27 health risks are associated with the management and disposal of coal combustion waste. Coal 

28 combustion generates waste in the form of ash, and equipment for controlling air pollution 

29 generates additional ash and scrubber sludge. Human health risks may extend beyond the 

30 facility workforce to the public depending on their proximity to the coal combustion waste 

31 disposal facility. The character and the constituents of coal combustion waste depend on both 

32 the chemical composition of the source coal and the technology used to combust it. Generally, 

33 the primary sources of adverse consequences from coal combustion waste are from exposure 

34 to sulfur oxide and nitrogen oxide in air emissions and radioactive elements such as uranium

35 and thorium as well as the heavy metals and hydrocarbon compounds contained in fly ash and 

36 bottom ash, and scrubber sludge (NRC 2013a).

37 Regulatory agencies, including EPA and state agencies, base air emission standards and 

38 requirements on human health impacts. These agencies also impose site-specific emission 

39 limits as needed to protect human health. Given the regulatory oversight exercised by EPA and 

40 state agencies, the NRC staff concludes that the human health impacts from radiological doses 

41 and inhaled toxins and particulates generated from the IGCC alternative would be SMALL 

42 (NRC 2013a).
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1 4.11.5 NGCC Alternative

2 Impacts on human health from construction of the NGCC alternative would be similar to effects 

3 associated with the construction of any major industrial facility. Compliance with worker 

4 protection rules would control those impacts on workers at acceptable levels. Impacts from 

5 construction on the general public would be minimal since crews would limit active construction 

6 area access to authorized individuals. Based on the above, the NRC staff concludes that the 

7 impacts on human health from the construction of the NGCC alternative would be SMALL.

8 Impacts from the operation of an NGCC facility introduces public risk from inhalation of gaseous 

9 emissions. The risk may be attributable to nitrogen oxide emissions that contribute to ozone 

10 formation, which in turn contribute to health risk. Regulatory agencies, including EPA and state 

11 agencies, base air emission standards and requirements on human health impacts. These 

12 agencies also impose site-specific emission limits as needed to protect human health. Given 

13 the regulatory oversight exercised by EPA and state agencies, the NRC staff concludes that the 

14 human health impacts from the NGCC alternative would be SMALL.

15 4.11.6 Combination Alternative (NGCC, Wind, Solar)

16 Impacts on human health from construction of a combination of NGCC, wind, and solar PV

17 alternatives would be similar to those associated with the construction of any major industrial 

18 facility. Compliance with worker protection rules would control those impacts on workers at 

19 acceptable levels. Impacts from construction on the general public would be minimal since 

20 crews would limit active construction area access to authorized individuals. Based on the 

21 above, the NRC staff concludes that the impacts on human health from the construction of the 

22 NGCC, wind, and solar alternative would be SMALL.

23 Operational hazards at an NGCC facility are similar to those at an IGCC facility and are 

24 discussed in Section 4.11.4.

25 Operational hazards at a wind facility for the workforce include working at heights, near rotating 

26 mechanical or electrically energized equipment, and working in extreme weather. Potential 

27 impacts to workers and the public include ice thrown from rotor blades and broken blades 

28 thrown due to mechanical failure. Potential impacts also include EMF exposure, aviation safety

29 hazard, and exposure to noise and vibration from the rotating blades.

30 Operational hazards at a solar PV facility may involve exposure to airborne toxic metals 

31 (e.g., cadmium) and silicon if the PV cell loses its integrity from a fire. Workers could also inhale 

32 silicon dust if the PV cell was smashed by an object or from a fall to the ground.

33 However, given the expected compliance with worker protection rules and remediation efforts to 

34 contain the toxic material, the potential impacts to workers at the facility and offsite exposure to 

35 the public, the impacts would be SMALL.

36 4.11.7 Purchased Power

37 Purchased power is expected to come from the types of electricity generation available within 

38 the ROI: coal, natural gas, nuclear, and wind. The human health impacts from the operation of 

39 these types of power plants are discussed in Sections 4.11.3, 4.11.4, 4.11.5, and 4.11.6. Based 

40 on the information in those sections, the NRC staff concludes that the human health impacts of 

41 the purchased power alternative using coal, natural gas, nuclear, and wind would be SMALL.
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1 4.12 Environmental Justice

2 This section describes the potential human health and environmental effects of the proposed 

3 action (license renewal) and alternatives to the proposed action on minority and low-income 

4 populations and special pathway receptors.

5 4.12.1 Proposed Action

6 The environmental justice issue applicable to Byron during the license renewal term is listed in 

7 Table 4–17. Section 3.12 of this SEIS describes the environmental justice matters with respect 

8 to Byron. 

9 Table 4–17. Environmental Justice

Issue GEIS Section Category

Minority and low-income populations 4.10.1 2

Source: Table B–1 in Appendix B, Subpart A, to 10 CFR Part 51

10 The NRC addresses environmental justice matters for license renewal by (1) identifying the 

11 location of minority and low-income populations that may be affected by the continued operation 

12 of the nuclear power plant during the license renewal term, (2) determining whether there would 

13 be any potential human health or environmental effects to these populations and special 

14 pathway receptors, and (3) determining if any of the effects may be disproportionately high and 

15 adverse. Adverse health effects are measured in terms of the risk and rate of fatal or nonfatal 

16 adverse impacts on human health. Disproportionately high and adverse human health effects 

17 occur when the risk or rate of exposure to an environmental hazard for a minority or low-income 

18 population is significant and exceeds the risk or exposure rate for the general population or for 

19 another appropriate comparison group. Disproportionately high environmental effects refer to 

20 impacts or risks of impacts on the natural or physical environment in a minority or low-income 

21 community that are significant and appreciably exceed the environmental impact on the larger 

22 community. Such effects may include biological, cultural, economic, or social impacts.

23 As discussed above, the environmental justice impact analysis evaluates the potential for 

24 disproportionately high and adverse human health and environmental effects on minority and 

25 low-income populations. Some of these potential effects have been identified in resource areas 

26 discussed in this SEIS. For example, increased demand for rental housing during replacement 

27 power plant construction could disproportionately affect low-income populations. Minority and 

28 low-income populations are subsets of the general public residing in the vicinity of all the 

29 alternatives listed below, and all are exposed to the same hazards generated by each 

30 alternative.

31 Figures 3–15 and 3–16 show the location of predominantly minority and low-income population 

32 block groups residing within a 50-mi (80-km) radius of Byron. This area of impact is consistent 

33 with the impact analysis for public and occupational health and safety, which also focuses on 

34 populations within a 50-mi (80-km) radius of the plant. Chapter 4 presents the assessment of 

35 environmental and human health impacts for each resource area. The analyses of impacts for 

36 all environmental resource areas indicated that the impact from license renewal would be 

37 SMALL.

38 Potential impacts on minority and low-income populations (including migrant workers or Native 

39 Americans) would mostly consist of socioeconomic and radiological effects; however, radiation 
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1 doses from continued operations during the license renewal term are expected to continue at 

2 current levels, and they would remain within regulatory limits. Section 4.11.1.2 of this SEIS 

3 discusses the environmental impacts from postulated accidents that might occur during the 

4 license renewal term, which include both design-basis and severe accidents. In both cases, the 

5 Commission has generically determined that impacts associated with DBAs are small because 

6 nuclear plants are designed and operated to successfully withstand such accidents, and the 

7 probability weighted consequences of severe accidents are small.

8 Therefore, based on this information and the analysis of human health and environmental 

9 impacts presented in Chapter 4 of this SEIS, there would be no disproportionately high and 

10 adverse human health and environmental effects on minority and low-income populations from 

11 the continued operation of Byron during the license renewal term.

12 As part of addressing environmental justice concerns associated with license renewal, the 

13 NRC staff also assessed the potential radiological risk to special population groups (such as 

14 migrant workers or Native Americans) from exposure to radioactive material received through

15 their unique consumption practices and interaction with the environment, including subsistence 

16 consumption of fish, native vegetation, surface waters, sediments, and local produce; 

17 absorption of contaminants in sediments through the skin; and inhalation of airborne radioactive 

18 material released from the plant during routine operation. This analysis is presented below.

19 Subsistence Consumption of Fish and Wildlife

20 The special pathway receptors analysis is an important part of the environmental justice

21 analysis because consumption patterns may reflect the traditional or cultural practices of 

22 minority and low-income populations in the area, such as migrant workers or Native Americans. 

23 Section 4-4 of Executive Order (EO) 12898 (1994) (59 FR 7629) directs Federal agencies, 

24 whenever practical and appropriate, to collect and analyze information about the consumption 

25 patterns of populations that rely principally on fish or wildlife for subsistence and to 

26 communicate the risks of these consumption patterns to the public. In this SEIS, the NRC staff 

27 considered whether there were any means for minority or low-income populations to be 

28 disproportionately affected by examining impacts on American Indian, Hispanics, migrant 

29 workers, and other traditional lifestyle special pathway receptors. The assessment of special 

30 pathways considered the levels of radiological and nonradiological contaminants in native 

31 vegetation, crops, soils and sediments, groundwater, surface water, fish, and game animals on 

32 or near Byron.

33 The following is a summary discussion of Exelon’s radiological environmental monitoring 

34 programs (REMPs) that assess the potential impacts from the subsistence consumption of fish 

35 and wildlife near the Byron site.

36 Exelon has an ongoing comprehensive REMP to assess the impact of Byron operations on the 

37 environment. To assess the impact of nuclear power plant operations, samples are collected 

38 annually from the environment and analyzed for radioactivity. A plant effect would be indicated 

39 if the radioactive material detected in a sample were significantly larger than background levels. 

40 Two types of samples are collected. The first type, a control sample, is collected from areas 

41 that are beyond the measurable influence of the nuclear power plant or any other nuclear 

42 facility. These samples are used as reference data to determine normal background levels of 

43 radiation in the environment. These samples are then compared with the second type of 

44 samples, indicator samples, collected near the nuclear power plant. Indicator samples are 

45 collected from areas where any contribution from the nuclear power plant will be at its highest 

46 concentration. These samples are then used to evaluate the contribution of nuclear power plant

47 operations to radiation or radioactivity levels in the environment. An effect would be indicated if 
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1 the radioactivity levels detected in an indicator sample were significantly larger than the control 

2 sample or background levels.

3 Samples of environmental media are collected from the aquatic and terrestrial pathways in the 

4 vicinity of Byron. The aquatic pathways include groundwater, surface water, fish, and shoreline 

5 sediment. The terrestrial pathways include airborne particulates, milk, and food products 

6 (i.e., cabbage, beets and beet greens, kohlrabi, potatoes, rhubarb leaves, onions, and turnips). 

7 During 2012, 1,480 analyses performed on 913 samples of environmental media at Byron 

8 showed no significant or measurable radiological impact above background levels from site 

9 operations (Teledyne 2013).

10 Conclusion

11 Based on the radiological environmental monitoring data from Byron, the NRC staff finds that no 

12 disproportionately high and adverse human health impacts would be expected in special 

13 pathway receptor populations in the region as a result of subsistence consumption of water, 

14 local food, fish, and wildlife. Continued operation of Byron would not have disproportionately 

15 high and adverse human health and environmental effects on these populations.

16 4.12.2 No-Action Alternative

17 Impacts on minority and low-income populations would depend on the number of jobs and the 

18 amount of tax revenues lost by communities in the immediate vicinity of the power plant after 

19 Byron ceases operations. Not renewing the operating licenses and terminating reactor

20 operations would have a noticeable impact on socioeconomic conditions in the communities 

21 located near Byron. The loss of jobs and income would have an immediate socioeconomic 

22 impact. Some, but not all, of the approximately 890 employees would begin to leave after 

23 reactor operations are terminated; and overall tax revenue generated by plant operations would 

24 be reduced. The reduction in tax revenue would decrease the availability of public services in 

25 Ogle County. This could disproportionately affect minority and low-income populations that may 

26 have become dependent on these services. Effects could be high or adverse depending on the 

27 needs of the individual impacted. See also Appendix J of NUREG–0586, Supplement 1 

28 (NRC 2002), for additional discussion of these impacts.

29 4.12.3 New Nuclear Alternative

30 Potential impacts to minority and low-income populations from the construction and operation of 

31 a new nuclear power plant would mostly consist of environmental and socioeconomic effects 

32 (e.g., noise, dust, traffic, employment, and housing impacts). Noise and dust impacts from 

33 construction would be short-term and primarily limited to onsite activities. Minority and 

34 low-income populations residing along site access roads would be affected by increased 

35 commuter vehicle traffic during shift changes and truck traffic. However, these effects would be 

36 temporary during certain hours of the day and would not likely be high and adverse. Increased 

37 demand for rental housing during construction could affect low-income populations. However, 

38 given the proximity of some existing nuclear power plant sites to metropolitan areas, many 

39 construction workers could commute to the site, thereby reducing the potential demand for 

40 rental housing.

41 Potential impacts to minority and low-income populations from new nuclear power plant 

42 operations would mostly consist of radiological effects; however, radiation doses are expected 

43 to be well below regulatory limits. All people living near the nuclear power plant would be 

44 exposed to the same potential effects from power plant operations, and any impacts would 
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1 depend on the magnitude of the change in ambient air quality conditions. Permitted air 

2 emissions are expected to remain within regulatory standards.

3 Based on this information and the analysis of human health and environmental impacts 

4 presented in this SEIS, the construction and operation of a new nuclear power plant would not 

5 have disproportionately high and adverse human health and environmental effects on minority 

6 and low-income populations.

7 4.12.4 IGCC Alternative

8 Potential impacts to minority and low-income populations from the construction and operation of 

9 a new IGCC plant at the Byron site or an existing power plant site would consist of 

10 environmental and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing 

11 impacts). Noise and dust impacts from construction would be short-term and primarily limited to 

12 onsite activities. Minority and low-income populations residing along site access roads would 

13 be affected by increased commuter vehicle traffic during shift changes and truck traffic. 

14 However, these effects would be temporary during certain hours of the day and would not likely 

15 be high and adverse. Increased demand for rental housing during construction could affect 

16 low-income populations. However, given the proximity of some existing power plant sites and 

17 the Byron site to metropolitan areas, many construction workers could commute to the site, 

18 thereby reducing the potential demand for rental housing.

19 Emissions from the operation of an IGCC plant could affect minority and low-income populations 

20 as well as the general population living in the vicinity of the new power plant. However, all 

21 would be exposed to the same potential effects from IGCC power plant operations and any 

22 impacts would depend on the magnitude of the change in ambient air quality conditions. 

23 Permitted air emissions are expected to remain within regulatory standards.

24 Based on this information and the analysis of human health and environmental impacts 

25 presented in this SEIS, the construction and operation of a new IGCC plant would not have 

26 disproportionately high and adverse human health and environmental effects on minority and 

27 low-income populations.

28 4.12.5 NGCC Alternative

29 Potential impacts to minority and low-income populations from the construction and operation of 

30 a new NGCC plant at the Byron site or an existing power plant site would mostly consist of 

31 environmental and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing 

32 impacts). Noise and dust impacts from construction would be short-term and primarily limited to 

33 onsite activities. Minority and low-income populations residing along site access roads would 

34 be affected by increased commuter vehicle traffic during shift changes and truck traffic. 

35 However, these impacts would only be during certain hours of the day and would not likely be 

36 high and adverse. Increased demand for rental housing during construction could affect 

37 low-income populations. However, given the proximity of some existing power plant sites and 

38 the Byron site to metropolitan areas, many construction workers could commute to the site, 

39 thereby reducing the potential demand for rental housing.

40 Emissions from the operation of an NGCC plant could affect minority and low-income 

41 populations as well as the general population living in the vicinity of the new power plant. 

42 However, all would be exposed to the same potential effects from NGCC power plant 

43 operations, and any impacts would depend on the magnitude of the change in ambient air 

44 quality conditions. Permitted air emissions are expected to remain within regulatory standards.
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1 Based on this information and the analysis of human health and environmental impacts 

2 presented in this SEIS, the construction and operation of a new NGCC plant would not have 

3 disproportionately high and adverse human health and environmental effects on minority and 

4 low-income populations.

5 4.12.6 Combination Alternative (NGCC, Wind, Solar)

6 Potential impacts to minority and low-income populations from the construction and operation of 

7 a new NGCC plant, wind turbines, and solar PV installations would mostly consist of 

8 environmental and socioeconomic effects (e.g., noise, dust, traffic, employment, and housing 

9 impacts). Noise and dust impacts from construction would be short-term and primarily limited to 

10 onsite activities. Minority and low-income populations residing along site access roads would 

11 be affected by increased commuter vehicle traffic during shift changes and truck traffic. 

12 However, these impacts would only be during certain hours of the day and would not likely be 

13 high and adverse. Increased demand for rental housing during construction could affect 

14 low-income populations. However, given the small number of construction workers and the 

15 possibility that many workers could commute to these construction sites, the potential need for 

16 rental housing would not be significant.

17 Minority and low-income populations living in close proximity to wind farm and solar PV power 

18 generating installations could be disproportionately affected by maintenance and operations

19 activities. However, everyone would be exposed to the same operational impacts, and any 

20 impact would depend on the magnitude of change from current conditions. Operational impacts 

21 from the wind turbines and solar PV installations would mostly be limited to noise and aesthetic

22 effects. The general public living near the wind farms and solar PV installations would also be 

23 exposed to the same effects.

24 Based on this information and the analysis of human health and environmental impacts 

25 presented in this SEIS, the construction and operation of a new NGCC plant, wind farms, and 

26 solar PV installations would not have disproportionately high and adverse human health and 

27 environmental effects on minority and low-income populations.

28 4.12.7 Purchased Power

29 Low-income populations could be disproportionately affected by increased utility bills because of

30 the cost of purchased power. However, programs, such as the low income home energy 

31 assistance program in Illinois, are available to assist low-income families in paying for increased 

32 electrical costs.

33 4.13 Waste Management and Pollution Prevention

34 This section describes the potential impacts of the proposed action (license renewal) and 

35 alternatives to the proposed action on waste management and pollution prevention.

36 4.13.1 Proposed Action

37 The waste management issues applicable to Byron are discussed below and listed in 

38 Table 4–18. Table B-1 of Appendix B to Subpart A of 10 CFR Part 51 contains more 

39 information on these issues.
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1 Table 4–18. Waste Management Issues

Issue GEIS Section Category

Low-level waste storage and disposal 4.11.1.1 1

Onsite storage of spent nuclear fuel 4.11.1.2(a) 1

Offsite radiological impacts of spent nuclear fuel and high-level waste

disposal 4.11.1.3(b) 1 

Mixed-waste storage and disposal 4.11.1.4 1

Nonradioactive waste storage 4.11.1.4 1

(a) The environmental impact of this issue for the timeframe beyond the licensed life for reactor operations is 

contained in NUREG-2157 (NRC 2014a).

(b) The environmental impact of this issue is contained in NUREG-2157 (NRC 2014a).

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51

2 The NRC staff’s evaluation of the environmental impacts associated with spent nuclear fuel is 

3 addressed in two issues in Table 4–18, “Onsite storage of spent nuclear fuel” and “Offsite 

4 radiological impacts of spent nuclear fuel and high-level waste disposal.” However, as 

5 explained later in this section, these two issues now incorporate the generic environmental 

6 impact determinations codified in the revised 10 CFR 51.23 pursuant to the Continued Storage 

Rule (79 FR 56238)

9 7 . 

8 The NRC staff did not identify any new and significant information related to waste management 

9 issues listed in Table 4–18 during its review of the applicant’s ER (Exelon 2013a), the site visit, 

10 or the scoping process. Therefore, there are no impacts related to these issues beyond those 

11 discussed in the GEIS (NRC 2013a) and the “Generic Environmental Impact Statement for 

12 Continued Storage of Spent Nuclear Fuel, Volumes 1 and 2” (NUREG-2157) (NRC 2014a). 

13 During the license renewal term, for these Category 1 issues discussed in the GEIS, the NRC 

14 staff concludes that the impacts are SMALL.

15 4.13.1.1 10 CFR 51.23 (Continued Storage Rule) and 10 CFR 51, Subpart A, Table B-1 

16 (License Renewal)

17 The NRC’s findings regarding the environmental impacts associated with the renewal of a 

18 power reactor operating license are contained in Table B-1, “Summary of Findings on NEPA

19 Issues for License Renewal of Nuclear Power Plants.” The table is located in Appendix B to 

20 Subpart A of 10 CFR Part 51, “Environmental Effect of Renewing the Operating License of a 

Nuclear Power Plant”10 21 (Table B-1). In 1996, as part of the 10 CFR Part 51 license renewal 

22 rulemaking, the NRC determined that offsite radiological impacts of spent nuclear fuel and 

23 high-level waste disposal would be a Category 1 (generic) issue with no impact level assigned 

24 (61 FR 28467, 28495; June 5, 1996). The NRC analyzed the EPA generic repository standards 

25 and dose limits in existence at the time and concluded that offsite radiological impacts 

26 warranted a Category 1 determination (61 FR 28467, 28478; June 5, 1996). In its 2009 

 

9 79 FR 56238. U.S. Nuclear Regulatory Commission. “Continued Storage of Spent Nuclear Fuel.” Federal Register 79 

(182):56238–56263. September 19, 2014.

10The Commission issued Table B-1 in June 1996 (61 FR 28467; June 5, 1996). The Commission issued an additional rule in 

December 1996 that made minor clarifying changes to, and added language inadvertently omitted from, Table B-1 (61 FR 66537; 

December 18, 1996). The NRC revised Table B-1 and other regulations in 10 CFR Part 51, relating to the NRC’s environmental 

review of a nuclear power plant’s license renewal application in a 2013 rulemaking (78 FR 37282; June 20, 2013). 
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1 proposed rule, the NRC stated its intention to reaffirm that determination (74 FR 38117, 38127; 

2 July 31, 2009). 

3 For the offsite radiological impacts resulting from spent fuel and high-level waste disposal and 

4 the onsite storage of spent fuel, which will occur after the reactors have been permanently 

5 shutdown, the NRC’s Waste Confidence Decision and Temporary Storage Rule (WCD and rule) 

6 (10 CFR 51.23) historically represented the Commission’s generic determination that spent fuel 

7 can continue to be stored safely and without significant environmental impacts for a period of 

8 time after the end of the licensed life for operation. This generic determination meant that the 

9 NRC did not need to consider the storage of spent fuel after the end of a reactor’s licensed life 

10 for operation in NEPA documents that support its reactor and spent fuel storage application 

11 reviews.

12 The NRC first adopted the Waste Confidence Decision and Rule in 1984. The NRC amended 

13 the decision and rule in 1990, reviewed them in 1999, and amended them again in 2010, as 

14 published in the Federal Register (FR) (49 FR 34685, 34694; 55 FR 38472, 38474; 

15 64 FR 68005; and 75 FR 81032 and 81037). The Waste Confidence Decision and Rule are 

16 codified in 10 CFR 51.23.

17 On December 23, 2010, the Commission published in the FR a revision of the Waste 

18 Confidence Decision and Rule to reflect information gained from experience in the storage of 

19 spent fuel and the increased uncertainty in the siting and construction of a permanent geologic 

20 repository for the disposal of spent fuel and high-level waste (75 FR 81032 and 81037). In 

21 response to the 2010 Waste Confidence Decision and Rule, the States of New York, 

22 New Jersey, Connecticut, and Vermont—along with several other parties—challenged the 

23 Commission’s NEPA analysis in the decision, which provided the regulatory basis for the rule. 

24 On June 8, 2012, the United States Court of Appeals, District of Columbia Circuit in 

25 New York v. NRC, 681 F.3d 471 (D.C. Cir. 2012), vacated the NRC’s Waste Confidence 

26 Decision and Rule after finding that it did not comply with NEPA.

27 In response to the court’s ruling, the Commission, in CLI-12-16 (NRC 2012a), determined that it 

28 would not issue licenses that rely upon the Waste Confidence Decision and Rule until the issues 

29 identified in the court’s decision are appropriately addressed by the Commission. In CLI-12-16, 

30 the Commission also noted that the decision not to issue licenses only applied to final license 

31 issuance; all licensing reviews and proceedings should continue to move forward.

32 In addition, the Commission directed in SRM-COMSECY-12-0016 (NRC 2012b) that the NRC 

33 staff proceed with a rulemaking that includes the development of a generic EIS to support a 

34 revised Waste Confidence Decision and Rule and to publish both the EIS and the revised 

35 decision and rule in the FR within 24 months (by September 2014). The Commission indicated 

36 that both the EIS and the revised Waste Confidence Decision and Rule should build on the 

37 information already documented in various NRC studies and reports, including existing EAs that 

38 the NRC developed as part of the 2010 Waste Confidence Decision and Rule. The Commission 

39 directed that any additional analyses should focus on the issues identified in the court’s 

40 decision. The Commission also directed that the NRC staff provide ample opportunity for public 

41 comment on both the draft EIS and the proposed Waste Confidence Decision and Rule.

42 As discussed above, in New York v. NRC, 681 F.3d 471 (D.C. Cir. 2012), the court vacated the 

43 Commission’s Waste Confidence Decision and Rule (10 CFR 51.23). In response to the court’s 

44 vacatur, the Commission developed a revised rule and associated Generic Environmental 

45 Impact Statement for Continued Storage of Spent-Nuclear Fuel (NUREG-2157). Before the 

46 issuance of the revised 10 CFR 51.23 and NUREG-2157, the NRC issued the 2013 final license 

47 renewal rule, which amended Table B-1—along with other 10 CFR Part 51 regulations—and

48 stated that upon finalization of the revised Waste Confidence rule and accompanying technical 
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analyses,11 1 the NRC would make any necessary conforming amendments to Table B-1 

2 (78 FR 37282, 37293; June 20, 2013).

3 On August 26, 2014, the Commission approved the Continued Storage Rule and associated 

4 Generic Environmental Impact Statement for Continued Storage of Spent Nuclear Fuel

5 (NUREG-2157, NRC 2014a). Subsequently, on September 19, 2014, the NRC published the 

6 final rule (79 FR 56238) in the Federal Register, along with NUREG-2157 (79 FR 53238, 

7 56263). The Continued Storage Rule adopts the generic impact determinations made in 

8 NUREG-2157 and codifies the NRC’s generic determinations regarding the environmental 

9 impacts of continued storage of spent nuclear fuel beyond a reactor’s operating license (i.e., 

10 those impacts that could occur as a result of the storage of spent nuclear fuel at at-reactor or 

11 away-from-reactor sites after a reactor’s licensed life for operation and until a permanent 

12 repository becomes available). As directed by 10 CFR 51.23(b), the impacts assessed in 

13 NUREG-2157 regarding continued storage are deemed incorporated by rule into this license 

14 renewal SEIS.

15 In the Continued Storage Rule, the NRC made conforming changes to the two environmental 

16 issues in Table B-1 that were impacted by the vacated Waste Confidence rule: “Onsite spent 

fuel” and “Offsite radiological impacts (spent fuel and high-level waste disposal).”12 17 Although 

18 NUREG-2157 (the technical basis for the Continued Storage Rule) does not include high-level 

19 waste disposal in the analysis of impacts, it does address the technical feasibility of a repository 

20 in Appendix B of NUREG-2157 and concludes that a geologic repository for spent fuel is 

21 technically feasible and the same analysis applies to the feasibility of geologic disposal for 

22 high-level waste.

23 The Commission revised the Table B-1 finding for “Onsite storage of spent nuclear fuel” to add 

24 the phrase “during the license renewal term” to make clear that the SMALL impact is for the 

25 license renewal term only. Some minor clarifying changes were also made to the paragraph. 

26 The first paragraph of the column entry now reads, “During the license renewal term, SMALL. 

27 The expected increase in the volume of spent nuclear fuel from an additional 20 years of 

28 operation can be safely accommodated onsite during the license renewal term with small 

29 environmental impacts through dry or pool storage at all plants.” 

30 In addition, a new paragraph is added to address the impacts of onsite storage of spent fuel

31 during the continued storage period. The second paragraph of the column entry reads, “For the 

32 period after the licensed life for reactor operations, the impacts of onsite storage of spent 

33 nuclear fuel during the continued storage period are discussed in NUREG-2157 and as stated in 

34 § 51.23(b), shall be deemed incorporated into this issue.” The changes reflect that this issue 

35 covers the environmental impacts associated with the storage of spent nuclear fuel during the 

36 license renewal term as well as the period after the licensed life for reactor operations.

37 The Table B-1 entry for “Offsite radiological impacts of spent nuclear fuel and high-level waste

38 disposal” also was revised to reclassify the impact determination as a Category 1 issue with no 

39 impact level assigned. The finding column entry for this issue includes reference to EPA’s 

40 radiation protection standards for the high-level waste and spent nuclear fuel disposal 

41 component of the fuel cycle. Although the status of a repository, including a repository at Yucca 

42 Mountain, is uncertain and outside the scope of the generic environmental analysis conducted 

 

11At the time of the 2013 final license renewal rule, the Continued Storage Rule was referred to by its long-standing historical 

moniker, Waste Confidence. 

12These two issues were renamed, ‘‘Onsite storage of spent nuclear fuel’ and ‘‘Offsite radiological impacts of spent nuclear fuel and 

high-level waste disposal,’’ respectively, by the 2013 license renewal rule. See “Revisions to Environmental Review for Renewal 

of Nuclear Power Plant Operating Licenses,” 78 FR 37282–37324 (June 20, 2013).
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1 to support the Continued Storage Rule, the NRC believes that the current radiation standards 

2 for Yucca Mountain are protective of public health and safety and the environment.

3 The changes to these two issues finalize the Table B-1 entries that the NRC had intended to 

4 issue in its 2013 license renewal rulemaking, but was unable to because the 2010 Waste 

5 Confidence rule had been vacated.

6 NUREG-2157 concludes that deep geologic disposal remains technically feasible, while the 

7 bases for the specific conclusions in Table B-1 are found elsewhere (e.g., the 1996 rule that 

8 issued Table B-1 and the 1996 license renewal GEIS, which provided the technical basis for 

9 that rulemaking, as reaffirmed by the 2013 rulemaking and final license renewal GEIS). Based 

10 on the Continued Storage Rule, these two issues were revised accordingly in Table B-1.

11 4.13.1.2 CLI-14-08: Holding that Revised 10 CFR 51.23 and NUREG-2157 Satisfy NRC’s 

12 NEPA Obligations for Continued Storage and Directing Staff to Account for 

13 Environmental Impacts In NUREG-2157

14 In CLI-14-08 (NRC 2014b), the Commission held that the revised 10 CFR 51.23 and associated 

15 NUREG-2157 cure the deficiencies identified by the court in New York and stated that the rule 

16 satisfies the NRC’s NEPA obligations with respect to continued storage for initial, renewed, and 

17 amended licenses for reactors.

18 As the Commission noted in CLI-14-08, the NRC staff must account for these environmental 

19 impacts before finalizing its licensing decision in this proceeding. To account for these impact 

20 determinations, the generic environmental impact determinations made pursuant to the 

21 Continued Storage Rule and the associated NUREG-2157 are deemed incorporated into this 

22 SEIS.

23 The NRC staff relies on the Continued Storage Rule and its supporting generic environmental 

24 impact statement (i.e., NUREG-2157) to provide the NEPA analyses of the environmental 

25 impacts of spent fuel storage at the reactor site or at an away-from-reactor storage facility 

26 beyond the licensed life for reactor operations. By virtue of the revised 10 CFR 51.23, the 

27 impact determinations in NUREG-2157 regarding continued storage complete the analysis of 

28 the environmental impacts associated with spent fuel storage beyond the licensed life for 

29 reactor operations and are deemed incorporated into this SEIS, as further described below. 

30 4.13.1.3 At-Reactor Storage

31 The analysis in NUREG-2157 concludes that the potential impacts of at-reactor storage during 

32 the short-term timeframe (the first 60 years after the end of licensed life for operations of the 

33 reactor) would be SMALL (see Section 4.20 of NUREG-2157). Furthermore, the analysis in 

34 NUREG-2157 states that disposal of the spent fuel by the end of the short-term timeframe is the 

35 most likely outcome (see Section 1.2 of NUREG-2157). 

36 However, the analysis in NUREG-2157 also evaluated the potential impacts of continued 

37 storage if the fuel is not disposed of by the end of the short-term timeframe. The analysis in 

38 NUREG-2157 determined that the impacts to historic and cultural resources from at-reactor

39 storage during the long-term timeframe (the 100-year period after the short-term timeframe) and 

40 the indefinite timeframe (the period after the long-term timeframe) are dependent on factors that 

41 are unpredictable this far in advance and therefore concluded those impacts would be SMALL 

42 to LARGE (see Section 4.12 of NUREG-2157). Among other things, as discussed in 

43 NUREG-2157, the NRC cannot accurately determine at this time what resources may be 

44 present or discovered at a continued storage site a century or more in the future and whether 

45 those resources will be historically or culturally significant to future generations. Additionally, 

46 impacts greater than SMALL could occur if the activities to replace an independent spent fuel 
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1 storage installation (ISFSI) and the dry transfer system (DTS) adversely affect cultural or historic 

2 resources and the effects cannot be mitigated. As discussed in NUREG-2157, given the 

3 minimal size of an ISFSI and DTS, and the large land areas at nuclear power plant sites, 

4 licensees should be able to locate these facilities away from historic and cultural resources. 

5 Potential adverse effects on historic properties or impacts on historic and cultural resources 

6 could also be minimized through development of agreements, license conditions, and 

7 implementation of the licensee’s historic and cultural resource management plans and 

8 procedures to protect known historic and cultural resources and address inadvertent discoveries 

9 during construction and replacement of these facilities. However, it may not be possible to 

10 avoid adverse effects on historic properties under the National Historic Preservation Act of 1966 

11 (NHPA), as amended, or impacts on historic and cultural resources under NEPA and, therefore, 

12 the analysis in NUREG-2157 concluded that impacts would be SMALL to LARGE (see 

13 Section 4.12.2 of NUREG-2157).

14 The analysis in NUREG-2157 also concludes that the impacts of nonradioactive waste in the 

15 indefinite timeframe would be SMALL to MODERATE, with the higher impacts potentially 

16 occurring if the waste from repeated replacement of the ISFSI and DTS exceeds local landfill 

17 capacity (see Section 4.15 of NUREG-2157). Although the NRC concluded that nonradioactive 

18 waste disposal would not be destabilizing (or LARGE), the range reflects uncertainty regarding 

19 whether the volume of nonradioactive waste from continued storage would contribute to 

20 noticeable waste management impacts over the indefinite timeframe when considered in the 

21 context of the overall local volume of nonradioactive waste. 

22 As previously discussed, the NRC found in NUREG-2157 that disposal of the spent fuel is most 

23 likely to occur by the end of the short-term timeframe. Therefore, disposal during the long-term 

24 timeframe is less likely, and the scenario depicted in the indefinite timeframe—continuing to 

25 store spent nuclear fuel indefinitely—is unlikely. As a result, the most likely impacts of the 

26 continued storage of spent fuel are those considered in the short-term timeframe. In the unlikely 

27 event that fuel remains on site into the long-term and indefinite timeframes, the associated 

28 impact ranges in NUREG-2157 reflect the accordingly greater uncertainties regarding the 

29 potential impacts over these very long periods of time. Taking into account the impacts that the 

30 NRC considers most likely, which are SMALL; the greater uncertainty reflected in the ranges in 

31 the long-term and indefinite timeframes compared to the greater certainty in the SMALL 

32 findings; and the relative likelihood of the timeframes, the impact determinations for at-reactor

33 storage presented in NUREG-2157 are deemed incorporated into this SEIS pursuant to 

34 10 CFR 51.23. 

35 4.13.1.4 Away-From-Reactor Storage

36 In NUREG-2157, the NRC concluded that a range of potential impacts could occur for some 

37 resource areas if the spent fuel from multiple reactors is shipped to a large (roughly 40,000 

38 metric tons Uranium) away-from-reactor ISFSI (see Section 5.20 of NUREG-2157). The ranges 

39 for some resources are driven by the uncertainty regarding the location of such a facility and the 

40 local resources that would be affected. 

41 For away-from-reactor storage, the unavoidable adverse environmental impacts for most 

42 resource areas is SMALL across all timeframes, except for air quality, terrestrial resources, 

43 aesthetics, waste management, and transportation where the impacts are SMALL to 

44 MODERATE. Socioeconomic impacts range from SMALL (adverse) to LARGE (beneficial) and 

45 historic and cultural resource impacts could be SMALL to LARGE across all timeframes. The 

46 potential MODERATE impacts on air quality, terrestrial wildlife, and transportation are based on 

47 potential construction-related fugitive dust emissions, terrestrial wildlife direct and indirect 

48 mortalities, terrestrial habitat loss, and temporary construction traffic impacts. The potential 
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1 MODERATE impacts on aesthetics and waste management are based on noticeable changes 

2 to the viewshed from constructing a new away-from-reactor ISFSI, and the volume of 

3 nonhazardous solid waste generated by assumed facility ISFSI and DTS replacement activities 

4 for the indefinite timeframe, respectively. The potential LARGE beneficial impacts on 

5 socioeconomics are due to local economic tax revenue increases from an away-from-reactor 

6 ISFSI.

7 The potential impacts to historic and cultural resources during the short-term storage timeframe 

8 would range from SMALL to LARGE. The magnitude of adverse effects on historic properties 

9 and impacts on historic and cultural resources largely depends on where facilities are sited, 

10 what resources are present, the extent of proposed land disturbance, whether the area has 

11 been previously surveyed to identify historic and cultural resources, and if the licensee has 

12 management plans and procedures that are protective of historic and cultural resources. Even 

13 a small amount of ground disturbance (e.g., clearing and grading) could affect a small but 

14 significant resource. In most instances, placement of storage facilities on the site can be 

15 adjusted to minimize or avoid impacts on any historic and cultural resources in the area. 

16 However, the NRC recognizes that this may not always be possible. The NRC’s site-specific 

17 environmental review and compliance with the NHPA process could identify historic properties, 

18 identify adverse effects, and potentially resolve adverse effects on historic properties and 

19 impacts on other historic and cultural resources. Under the NHPA, mitigation does not eliminate 

20 a finding of adverse effect on historic properties. The potential impacts to historic and cultural 

21 resources during the long-term and indefinite storage timeframes would also range from SMALL 

22 to LARGE. This range takes into consideration routine maintenance and monitoring (i.e., no 

23 ground-disturbing activities), the absence or avoidance of historic and cultural resources, and 

24 potential ground-disturbing activities that could affect historic and cultural resources. The 

25 analysis also considers uncertainties inherent in analyzing this resource area over long 

26 timeframes. These uncertainties include any future discovery of previously unknown historic 

27 and cultural resources; resources that gain significance within the vicinity and the viewshed 

28 (e.g., nomination of a historic district) due to improvements in knowledge, technology, and 

29 excavation techniques and changes associated with predicting resources that future 

30 generations will consider significant. If construction of a DTS and replacement of the ISFSI and 

31 DTS occurs in an area with no historic or cultural resource present or construction occurs in a 

32 previously disturbed area that allows avoidance of historic and cultural resources, then impacts 

33 would be SMALL. By contrast, a MODERATE or LARGE impact could result if historic and 

34 cultural resources are present at a site and, because they cannot be avoided, are impacted by 

35 ground-disturbing activities during the long-term and indefinite timeframes. 

36 Impacts on Federally listed species, designated critical habitat, and essential fish habitat would 

37 be based on site-specific conditions and determined as part of consultations required by the 

38 Endangered Species Act and the Magnuson-Stevens Fishery Conservation and Management 

39 Act. 

40 Continued storage of spent nuclear fuel at an away-from-reactor ISFSI is not expected to cause 

41 disproportionately high and adverse human health and environmental effects on minority and 

42 low-income populations. As indicated in the Commission’s policy statement on environmental 

43 justice, should the NRC receive an application for a proposed away-from-reactor ISFSI, a site44 specific NEPA analysis would be conducted, and this analysis would include consideration of 

45 environmental justice impacts. Pursuant to 10 CFR 51.23, the impact determinations for away46 from-reactor storage presented in NUREG-2157 are deemed incorporated into this SEIS.
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1 4.13.1.5 Cumulative Impacts

2 NUREG-2157 examines the incremental impact of continued storage on each resource area 

3 analyzed in NUREG-2157 in combination with other past, present, and reasonably foreseeable 

4 future actions. NUREG-2157 indicates ranges of potential cumulative impacts for multiple 

5 resource areas (see Section 6.5 of NUREG-2157). However, these ranges are primarily driven 

6 by impacts from activities other than the continued storage of spent fuel at the reactor site; the 

7 impacts from these other activities would occur regardless of whether spent nuclear fuel is 

8 stored during the continued storage period. In the short-term timeframe, which is the most likely 

9 timeframe for the disposal of the fuel, the potential impacts of continued storage for at-reactor 

10 storage are SMALL and would, therefore, not be a significant contributor to the cumulative 

11 impacts. In the longer timeframes for at-reactor storage, or in the less likely case of away-from12 reactor storage, some of the impacts from the storage of spent nuclear fuel could be greater 

13 than SMALL. As noted in NUREG-2157, other Federal and non-Federal activities occurring 

14 during the longer timeframes include uncertainties as well. It is primarily these uncertainties 

15 (i.e., those associated with activities other than continued storage) that contribute to the ranges 

16 of potential cumulative impacts discussed throughout Chapter 6 of NUREG-2157 and 

17 summarized in Table 6-4 of NUREG-2157. Because, as stated above, the impacts from these 

18 other activities would occur regardless of whether continued storage occurs, the overall 

19 cumulative impact conclusions in NUREG-2157 would still be the stated ranges regardless of 

20 whether there are impacts of continued storage from any individual licensing action. 

21 Taking into account the impacts that the NRC considers most likely, which are SMALL; the 

22 uncertainty reflected by the ranges in some impacts; and the relative likelihood of the 

23 timeframes, the impact determinations for cumulative impacts presented in NUREG-2157 are 

24 deemed incorporated into this SEIS pursuant to 10 CFR 51.23.

25 4.13.1.6 Conclusion

26 Based on the information discussed above, the impacts of continued storage of spent nuclear 

27 fuel are those presented in NUREG-2157 and are deemed incorporated into this SEIS pursuant 

28 to 10 CFR 51.23. In addition, the revised 10 CFR 51.23 and NUREG-2157 have gone through 

29 the rulemaking process that involved significant input from the public. Therefore, the NRC staff 

30 concludes that the information in NUREG-2157 provides the appropriate NEPA analyses of the 

31 potential environmental impacts associated with the continued storage of spent fuel beyond the 

32 licensed life for reactor operations at Byron Station. 

33 The NRC staff concludes that the revised 10 CFR 51.23, which adopts the generic impact 

34 determination regarding continued storage from NUREG-2157, satisfies the NRC’s NEPA

35 obligations with respect to continued storage of spent nuclear fuel, as it relates to the issues, 

36 “Onsite storage of spent nuclear fuel” and “Offsite radiological impacts of spent nuclear fuel and 

37 high-level waste disposal” for the environmental review associated the license renewal for 

38 Byron. 

39 4.13.2 No-Action Alternative

40 If the no-action alternative were implemented, Byron would cease operation at the end of the 

41 initial operating licenses, or sooner, and enter decommissioning. The plants, which are 

42 currently operating within regulatory limits, would generate less spent nuclear fuel and emit less 

43 gaseous and liquid radioactive effluents into the environment. In addition, following shutdown, 

44 the variety of potential accidents at the plants (radiological and industrial) would be reduced to a 

45 limited set associated with shutdown events and fuel handling and storage. In Section 4.11 of 

46 this SEIS, the NRC staff concluded that the impacts of continued operations on human health 

47 would be SMALL. In Section 4.11 of this SEIS, the NRC staff concluded that the impacts of 
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1 accidents would be SMALL. In Section 4.15.2 of this SEIS the NRC staff concludes that the 

2 impacts from decommissioning would be SMALL. Therefore, as radioactive emissions to the 

3 environment decrease, and the likelihood and variety of accidents decrease following shutdown 

4 and decommissioning, the NRC staff concludes that the risk to human health following plant 

5 shutdown would be SMALL.

6 4.13.3 New Nuclear Alternative

7 Construction-related debris would be generated during construction activities, and would be 

8 recycled or disposed of in approved landfills.

9 During normal plant operations, routine plant maintenance, and cleaning activities would 

10 generate radioactive low-level waste, spent nuclear fuel, and high-level waste as well as 

11 nonradioactive waste. Sections 3.1.4 and 3.1.5 discuss radioactive and nonradioactive waste 

12 management at Byron. Quantities of radioactive and nonradioactive waste generated by Byron 

13 would be comparable to that generated by the two new nuclear plants.

14 According to the GEIS (NRC 1996, 2013a), the generation and management of solid radioactive 

15 and nonradioactive waste during the license renewal term are not expected to result in 

16 significant environmental impacts.

17 Based on this information, the waste impacts would be SMALL for the new nuclear alternative.

18 4.13.4 IGCC Alternative

19 Construction-related debris would be generated during plant construction activities, and would 

20 be recycled or disposed of in approved landfills. The amount of the construction waste would 

21 be small compared to the amount of waste generated during the operational stage and much of 

22 it could be recycled (i.e., marketed for beneficial use).

23 Coal combustion generates waste in the form of fly ash and bottom ash. In addition, equipment 

24 for controlling air pollution generates additional ash, spent SCR catalyst, and scrubber sludge. 

25 The management and disposal of the large amounts of coal combustion waste is a significant 

26 part of the operation of a coal-fired power generating facility.

27 Although an IGCC facility is likely to use offsite disposal of coal combustion waste, some 

28 short-term storage of coal combustion waste (either in open piles or in surface impoundments) 

29 is likely to take place on site, thus establishing the potential for leaching of toxic chemicals into 

30 the local environment.

31 The impacts of managing the substantial amounts of solid waste, especially fly ash and 

32 scrubber sludge generated during operation of this alternative would be MODERATE 

33 (NRC 1996).

34 Therefore, the staff concludes that the overall waste management impacts from construction 

35 and operation of this alternative would be SMALL to MODERATE.

36 4.13.5 NGCC Alternative

37 Construction-related debris would be generated during plant construction activities, and would 

38 be recycled or disposed of in approved landfills.

39 Waste generation from NGCC technology would be minimal. The only significant waste 

40 generated at an NGCC power plant would be spent SCR catalyst, which is used to control 

41 nitrogen oxide emissions.
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1 The spent catalyst would be regenerated or disposed of off site. Other than spent SCR catalyst, 

2 waste generation at an operating natural gas-fired plant would be limited largely to typical 

3 operations and maintenance nonhazardous waste. Overall, the NRC staff concludes that waste 

4 impacts from the NGCC alternative would be SMALL.

5 4.13.6 Combination Alternative (NGCC, Wind, Solar)

6 Construction-related debris would be generated during construction activities, and would be 

7 recycled or disposed of in approved landfills.

8 Waste generation from NGCC technology would be minimal. The only significant waste

9 generated at an NGCC power plant would be spent SCR catalyst, which is used to control 

10 nitrogen oxide emissions.

11 Waste generation from a combination of wind and solar PV alternatives would be minimal, 

12 consisting of debris from routine maintenance and the disposal of worn or broken parts. Based 

13 on this information, the NRC staff concludes that waste impacts from the construction and 

14 operation of a combination wind and solar PV alternative would be SMALL.

15 4.13.7 Purchased Power

16 The types of waste generated by the alternative electricity generation sources (i.e., coal, natural 

17 gas, nuclear, and wind) used in the purchased power alternative are discussed in 

18 Sections 4.13.3, 4.13.4, 4.13.5, and 4.13.6. Depending on types of power-generation plants 

19 used to provide the electricity for the purchased power alternative, the NRC staff concludes that 

20 the waste management impacts would range from SMALL to MODERATE.

21 4.14 Evaluation of New and Potentially Significant Information

22 New and significant information is information that must be new, based on a review of the GEIS

23 (NRC 2013a) and codified in Table B-1 of 10 CFR Part 51, Subpart A, Appendix B, and must 

24 bear on the proposed action or its impacts, presenting a seriously different picture of the 

25 impacts from those envisioned in the GEIS (i.e., impacts of greater severity than impacts 

26 considered in the GEIS, considering their intensity and context).

27 In accordance with 10 CFR 51.53(c), the ER that the applicant submits must provide an analysis 

28 of the Category 2 issues in Table B-1 of 10 CFR Part 51, Subpart A, Appendix B. Additionally, it 

29 must discuss actions to mitigate any adverse impacts associated with the proposed action and 

30 environmental impacts of alternatives to the proposed action. In accordance with 

31 10 CFR 51.53(c)(3), the ER does not need to contain an analysis of any Category 1 issue 

32 unless there is new and significant information on a specific issue.

33 The NRC process for identifying new and significant information is described in NUREG–1555, 

34 Supplement 1, Standard Review Plans for Environmental Reviews for Nuclear Power Plants, 

35 Supplement 1: Operating License Renewal (NRC 1999, 2013ai). The search for new 

36 information includes:

37 • review of an applicant’s ER and the process for discovering and evaluating 

38 the significance of new information;

39 • review of public comments; 

40 • review of environmental quality standards and regulations; 
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1 • coordination with Federal, state, local, and tribal environmental protection and 

2 resource agencies; and

3 • review of the technical literature.

4 New information that the staff discovers is evaluated for significance using the criteria set forth 

5 in the GEIS. For Category 1 issues in which new and significant information is identified, 

6 reconsideration of the conclusions for those issues is limited in scope to assessment of the 

7 relevant new and significant information; the scope of the assessment does not include those

8 facets of an issue that are not affected by the new information.

9 The NRC staff reviewed the discussion of environmental impacts associated with operation 

10 during the renewal term in the GElS and has conducted its own independent review, including a 

11 public involvement process (e.g., public meetings) to identify new and significant issues for the 

12 Byron license renewal application environmental review. The NRC staff has not identified new 

13 and significant information on environmental issues related to operation of Byron during the 

14 renewal term. The NRC staff also determined that information provided during the public 

15 comment period did not identify any new issue that requires site-specific assessment. 

16 4.15 Impacts Common to All Alternatives

17 This section describes the impacts that are considered common to all alternatives discussed in 

18 this SEIS, including the proposed action and replacement power alternatives. The continued 

19 operation of a nuclear power plant and replacement fossil fuel power plants both involve mining, 

20 processing, and the consumption of fuel, which results in comparative impacts (NRC 2013a). 

21 The termination of operations and the decommissioning of both a nuclear power plant and 

22 replacement fossil fueled power plants are also discussed in the following sections, as well as 

23 GHG emissions.

24 4.15.1 Fuel Cycle

25 This section describes the environmental impacts associated with the fuel cycles of the 

26 proposed action and replacement power alternatives. Most replacement power alternatives 

27 employ a set of steps in the utilization of their fuel sources, which can include extraction, 

28 transformation, transportation, and combustion. Emissions generally occur at each stage of the 

29 fuel cycle (NRC 2013a).

30 4.15.1.1 Uranium Fuel Cycle

31 The uranium fuel cycle issues applicable to Byron are discussed below and listed in Table 4–19 

32 for Category 1 issues. Table B-1 of Appendix B to Subpart A of 10 CFR Part 51 contains more 

33 information on these issues.
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1 Table 4–19. Issues Related to the Uranium Fuel Cycle

Issue GEIS Section Category

Offsite radiological impacts—individual impacts from other than the 

disposal of spent fuel and high-level waste 4.12.1.1 1 

Office radiological impacts—collective impacts from other than the 

disposal of spent fuel and high-level waste 4.12.1.1 1 

Nonradiological impacts of the uranium fuel cycle 4.12.1.1 1

Transportation 4.12.1.1 1

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51

2 The uranium fuel cycle includes uranium mining and milling, the production of uranium 

3 hexafluoride, isotopic enrichment, fuel fabrication, reprocessing of irradiated fuel, transportation 

4 of radioactive materials, and management of low-level wastes and high-level wastes related to 

5 uranium fuel cycle activities. The generic potential impacts of the radiological and 

6 nonradiological environmental impacts of the uranium fuel cycle and transportation of nuclear 

7 fuel and wastes are described in detail in NUREG–1437, Generic Environmental Impact 

8 Statement (GEIS) for License Renewal of Nuclear Plants (NRC 1996, 1999, 2013a).

9 The NRC staff did not identify any new and significant information related to the uranium fuel 

10 cycle issues listed in Table 4–19 during its review of the applicant’s ER (Exelon 2013a), the site 

11 visit, and the scoping process. Therefore, there are no impacts related to these issues beyond 

12 those discussed in the GEIS. For these Category 1 issues, the GEIS concludes that the 

13 impacts are SMALL, except for the issue, “Offsite radiological impacts—collective impacts,” to 

14 which the NRC has not assigned an impact level. This issue assesses the 100-year radiation 

15 dose to the U.S. population (i.e., collective effects or collective dose) from radioactive effluent 

16 released as part of the uranium fuel cycle for a nuclear power plant during the license renewal 

17 term compared to the radiation dose from natural background exposure. It is a comparative 

18 assessment for which there is no regulatory standard to base an impact level.

19 4.15.1.2 Replacement Power Plant Fuel Cycles

20 Fossil Fuel Energy Alternatives

21 Fuel cycle impacts for a fossil-fuel-fired plant result from the initial extraction of fuel, cleaning 

22 and processing of fuel, transport of fuel to the facility, and management and ultimate disposal of 

23 solid wastes from fuel combustion. These impacts are discussed in more detail in 

24 Section 4.12.1.2 of the GEIS (NRC 2013a) and can generally include:

25 • significant changes to land use and visual resources;

26 • impacts to air quality, including release of criteria pollutants, fugitive dust, 

27 VOCs, and coalbed methane in the atmosphere;

28 • noise impacts;

29 • geology and soil impacts due to land disturbances and mining;

30 • water resource impacts, including degradation of surface water and 

31 groundwater quality;

32 • ecological impacts, including loss of habitat and wildlife disturbances;

33 • historic and cultural resources impacts within the mine footprint;
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1 • socioeconomic impacts from employment of both the mining workforce and 

2 service and support industries;

3 • environmental justice impacts;

4 • health impacts to workers from exposure to airborne dust and methane 

5 gases; and

6 • generation of coal and industrial wastes.

7 New Nuclear Energy Alternatives

8 Fuel cycle impacts for a nuclear plant result from the initial extraction of fuel, transport of fuel to 

9 the nuclear plant, and management and ultimate disposal of spent fuel. The environmental 

10 impacts of the uranium fuel cycle are discussed above, in Section 4.15.1.1.

11 Renewable Energy Alternatives

12 The term “fuel cycle” has varying degrees of relevance for renewable energy facilities. The term 

13 has meaning for renewable energy technologies that rely on combustion of fuels such as 

14 biomass grown or harvested for the express purpose of power production. The term is 

15 somewhat more difficult to define for renewable technologies such as wind, solar, geothermal, 

16 and ocean wave and current. Those natural energy resources exist regardless of any effort to 

17 harvest them for electricity production. The common technological strategy for harvesting 

18 energy from such natural resources is to convert the kinetic or thermal energy inherent in that 

19 resource to mechanical energy or torque. The torque is then applied directly (e.g., as in the 

20 case of a wind turbine) or indirectly (e.g., for those facilities that use conventional steam cycles 

21 to drive turbines that drive generators) to produce electricity. However, because those 

22 renewable technologies capture very small fractions of the total kinetic or thermal energy 

23 contained in those resources, impacts from the presence or absence of the renewable energy 

24 technology are often indistinguishable (NRC 2013a).

25 4.15.2 Terminating Power Plant Operations and Decommissioning

26 This section describes the environmental impacts associated with the termination of operations 

27 and the decommissioning of a nuclear power plant and replacement power alternatives. All 

28 operating power plants will terminate operations and be decommissioned at some point after the 

29 end of their operating life or after a decision is made to cease operations. For the proposed 

30 action, license renewal would delay this eventuality for an additional 20 years beyond the 

31 current license period, which ends in 2024 and 2026 for Byron Units 1 and 2, respectively.

32 4.15.2.1 Existing Nuclear Power Plant

33 Environmental impacts from the activities associated with the decommissioning of any reactor

34 before or at the end of an initial or renewed license are evaluated in Supplement 1 of 

35 NUREG–0586, Final Generic Environmental Impact Statement on Decommissioning of Nuclear 

36 Facilities Regarding the Decommissioning of Nuclear Power Reactors (NRC 2002). 

37 Additionally, the incremental environmental impacts associated with decommissioning activities 

38 resulting from continued plant operation during the renewal term are discussed in the GEIS.

39 Table 4–20 lists the Category 1 issues in Table B-1 of Title 10 of the CFR Part 51, Subpart A, 

40 Appendix B that are applicable to Byron decommissioning following the license renewal term.
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1 Table 4–20. Issues Related to Decommissioning

Issue GEIS Section Category

Radiation doses 4.12.2.1 1

Waste management 4.12.2.1 1

Air quality 4.12.2.1 1

Water quality 4.12.2.1 1

Ecological resources 4.12.2.1 1

Socioeconomic impacts 4.12.2.1 1

Source: Table B-1 in Appendix B, Subpart A, to 10 CFR Part 51

2 Decommissioning would occur whether Byron were shut down at the end of its current operating 

3 license or at the end of the period of the license renewal term. Exelon stated in its ER 

4 (Exelon 2013a) that it is not aware of any new and significant information on the environmental 

5 impacts of Byron during the license renewal term. The NRC staff has not found any new and 

6 significant information during its independent review of Exelon’s ER, the site visit, or the scoping

7 process. Therefore, the NRC staff concludes that there are no impacts related to these issues, 

8 beyond those discussed in the GEIS. For all of these issues, the NRC staff concluded in the 

9 GEIS that the impacts are SMALL.

10 4.15.2.2 Replacement Power Plants

11 Fossil Fuel Energy Alternatives

12 The environmental impacts from the termination of power plant operations and 

13 decommissioning of a fossil-fuel-fired plant are dependent on the facility’s decommissioning 

14 plan. General elements and requirements for a fossil fuel plant decommissioning plan are 

15 discussed in Section 14 of the GEIS and can include the removal of structures to at least 3 ft 

16 (1 m) below grade, removal of all coal, combustion waste, and accumulated sludge, removal of 

17 intake and discharge structures, and the cleanup and remediation of incidental spills and leaks 

18 at the facility. The decommissioning plan outlines the actions necessary to restore the site to a 

19 condition equivalent in character and value to the site on which the facility was first constructed 

20 (NRC 2013a).

21 The environmental consequences of decommissioning are discussed in Section 4.12.2.2 of the 

22 GEIS and can generally include:

23 • short-term impacts on air quality and noise from the deconstruction of facility 

24 structures,

25 • short-term impacts on land use and visual resources,

26 • long-term reestablishment of vegetation and wildlife communities,

27 • socioeconomic impacts due to decommissioning workforce and the long-term 

28 loss of jobs, and

29 • elimination of health and safety impacts on operating personnel and general 

30 public.
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1 New Nuclear Alternatives

2 Termination of operations and decommissioning impacts for a nuclear plant include all activities 

3 related to the safe removal of the facility from service and the reduction of residual radioactivity 

4 to a level that permits release of the property under restricted conditions or unrestricted use and 

5 termination of a license (NRC 2013a). The environmental impacts of the uranium fuel cycle are 

6 discussed above, in Section 4.15.1.1.

7 Renewable Alternatives

8 Termination of power plant operation and decommissioning for renewable energy facilities 

9 would be similar to the impacts discussed for fossil-fuel-fired plants above. Decommissioning 

10 would involve the removal of facility components and operational wastes and residues in order 

11 to restore the site to a condition equivalent in character and value to the site on which the facility 

12 was first constructed (NRC 2013a).

13 4.15.3 Greenhouse Gas Emissions and Climate Change

14 The following sections discuss GHG emissions released from operation of Byron Station and 

15 the environmental impacts that could occur from changes in climate conditions. The cumulative 

16 impacts of GHG emissions on climate are discussed in Section 4.16.11, Global Climate 

17 Change.

18 4.15.3.1 Greenhouse Gas Emissions From the Proposed Project and Alternatives

19 Gases found in the Earth’s atmosphere that trap heat and play a role in Earth’s climate are 

20 collectively termed GHGs. GHGs include carbon dioxide (CO2), methane (CH4), nitrous oxide 

21 (N2O), water vapor (H2O), and fluorinated gases such as hydrofluorocarbons (HFCs), 

22 perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). Earth’s climate responds to changes in 

23 concentration of GHG in the atmosphere as GHGs affect the amount of energy absorbed and 

24 heat trapped by the atmosphere. Increasing GHG concentration in the atmosphere generally 

25 increases Earth’s surface temperature. Atmospheric concentrations of carbon dioxide, 

26 methane, and nitrous oxide have significantly increased since 1750 (Solomon et al. 2007). 

27 Carbon dioxide, methane, nitrous oxide, HFCs, PFCs, and sulfur hexafluoride (termed long-lived 

28 GHGs) are well-mixed throughout Earth’s atmosphere and their impact on climate is long-lasting 

29 as a result of their long atmospheric lifetime (EPA 2009b). Carbon dioxide is of primary concern 

30 for global climate change due to its long atmospheric lifetime, and it is the primary gas emitted 

31 as a result of human activities. Climate change research indicates that the cause of the Earth’s 

32 warming over the last 50 years is due to the buildup of GHGs in atmosphere resulting from 

33 human activities (Melillo et al. 2014).

34 Proposed Action

35 Plant operations at Byron Station release GHG emissions (primarily carbon dioxide) from 

36 stationary combustion sources, such as standby emergency diesel generators, auxiliary boilers, 

37 auxiliary feedwater (AFW) pumps, SX makeup water pumps, and a fire pump. Other sources 

38 include mobile combustion sources (e.g., compressors, generators) and vehicle traffic (such as 

39 workers and delivery). Fluorinated gases are used as the refrigerant in air conditioning and 

40 refrigeration systems and in electrical transmission and distribution systems. These fluorinated 

41 gases are typically emitted in small quantities but their impacts could be substantial because of 

42 high global warming potential.

43 The GHG emissions generated directly and indirectly by an entity can be classified into 

44 three “Scopes,” based on the source of the emissions (EPA 2013a). Scope 1 GHG emissions 

45 are direct emissions that are owned or controlled by the entity, which include emissions from 
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1 fossil fuels burned on site, emissions from entity-owned or entity-leased vehicles, and other 

2 direct sources. Scope 2 GHG emissions are indirect emissions resulting from the generation of 

3 electricity, heating/cooling, or steam generated off site but purchased by the reporting entity. 

4 Scope 3 GHG emissions are indirect emissions from sources not owned or directly controlled by 

5 the reporting entity but related to the entity’s activities such as vendor supply chains, delivery 

6 services, outsourced activities, and employee travel and commuting. GHG emissions from 

7 nuclear power plants including Byron Station belong to all three Scopes. Annual total GHG 

8 emissions at Byron Station are presented in Table 4–21 for the 2008 to 2012 period. Direct 

9 emissions include permitted combustion sources only, which are reported to the IEPA per the 

10 requirements of 35 IAC Part 254 (Exelon 2009, 2010, 2011, 2012, 2013c). Total (direct plus 

11 indirect) GHG emissions include permitted combustion sources (diesel generators and auxiliary 

12 boilers), fugitive gas emissions, direct fluorinated gases, indirect purchased electricity, and 

13 ozone depleting substances from refrigerants. However, total emissions do not include GHG 

14 emissions from mobile sources because Exelon does not compile site-specific data for such 

15 sources (Exelon 2013b). The NRC staff estimates annual GHG emission resulting from 

16 employee vehicles to be approximately 8,400 MT CO2e. 

17 Table 4–21. Estimated GHG Emissions From Operations at Byron Station

Year CO2e (MT/year)

2008 12,102

2009 10,872

2010 12,059

2011 12,017

2012 13,962

Source: Exelon 2013b

18 No-Action Alternative

19 As discussed in previous no-action alternative sections, the no-action alternative represents a 

20 decision by the NRC not to renew the operating license of a nuclear power plant beyond the 

21 current operating license term. At some point, all nuclear plants will terminate operations and 

22 undergo decommissioning. Under the no-action alternative, plant operations for Byron would 

23 terminate at or before the end of the current license term (NRC 2013a). When the plant stops 

24 operating, there will be a reduction in GHG emissions from activities related to plant operation, 

25 such as use of diesel generators and employee vehicles. GHG emissions are anticipated to be 

26 less than what is presented in Table 4–21.

27 New Nuclear Alternative

28 As discussed in Section 2.2.2.2, the NRC staff evaluated the new nuclear power plant 

29 alternative that would consist of two units with an approximate generating capacity of 

30 1,120 MWe each. The GEIS presents life-cycle GHG emissions associated with nuclear power 

generation. As presented in Tables 4.12-4 through 4.12-6 of the GEIS, life-cycle 13 31 GHG 

32 emissions from nuclear power generation can range from 1 to 288 g carbon equivalent per 

33 kilowatt-hour (Ceq/kWh). Operation of nuclear power plants does not burn fossil fuels to 

 

13Life-cycle carbon emissions analyses consider construction, operation, decommissioning, and associated processing of fuel (gas, 

coal, etc.).
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1 generate electricity and so does not directly emit GHG emissions. Sources of GHG emissions 

2 include stationary combustion sources (e.g., emergency diesel generators, diesel-driven fire 

3 pumps, auxiliary boilers) and mobile sources (worker vehicles, onsite heavy equipment and 

4 support vehicles, and delivery of materials and disposal of wastes). As discussed in 

5 Section 4.3.3.1, it is anticipated that air emissions from a new nuclear power plant would be 

6 similar to those from Byron.

7 IGCC Generation Alternative

8 As discussed in Section 2.2.2.2, the NRC staff evaluated the IGCC plant alternative that would 

9 consist of four units with a total output of 2,472 MW. 

10 The IGCC alternative would release GHGs. The NRC staff estimates that operation of 

11 four IGCC units will directly emit about 14.3 million t (approximately 12.9 million MT) per year of 

12 CO2e. 

13 Emissions were estimated for the IGCC alternative without CCS. Among the alternatives, GHG 

14 emissions are the highest from IGCC plants. As described in Chapter 2, the IGCC alternative 

15 assumes that the plants may install CCS technology at some point in the future, which would 

16 reduce carbon dioxide emissions considerably. The DOE’s National Energy Technology 

17 Laboratory (NETL) performed a study to establish the cost and performance for a range of 

18 carbon dioxide capture levels (up to 97 percent) for new IGCC power plants (NETL 2013a). The 

19 study identified technical configurations that were tailored to achieve a specific level of carbon 

20 capture.

21 NGCC Generation Alternative

22 As discussed in Section 2.2.2.3, the NRC staff evaluated an NGCC alternative that consists of 

23 five NGCC 560-MWe units (total 2,800 MWe). The GEIS presents life-cycle GHG emissions 

24 associated with natural gas power generation. As presented in Table 4.12-5 of the GEIS, 

25 life-cycle GHG emissions from natural gas can range from 120 to 930 g Ceq/kWh. The NRC 

26 staff estimates that operation of the NGCC alternative directly will emit about 7.9 million t 

27 (approximately 7.2 million MT) per year of CO2e emissions.

28 Combination Alternative (NGCC, Wind, and Solar)

29 For this combination alternative, it is assumed that the majority of the GHG emissions result 

30 from the NGCC portion only because renewable portions (wind and solar PV) do not burn fossil 

31 fuels to generate electricity. As discussed in Section 4.3.6.1, GHG emissions associated with 

32 the operation of the NGCC portion are reduced proportionally because its electricity output is 

33 approximately 13 percent that of the NGCC alternative. The NRC staff estimates that operation 

34 of the combination alternative will directly emit 1.0 million t (0.9 million MT) per year of CO2e. 

35 Purchased Power Alternative

36 Purchased power would come from common types of existing technology (coal, natural gas, 

37 nuclear, and renewable sources) within the ROI and it is not likely that new facilities would be 

38 constructed to replace Byron. GHG emissions from purchased power will vary and depend on 

39 the type and combination of technology purchased power comes from. In 2012, coal, natural 

40 gas, and nuclear power accounted for 37-, 30-, and 19-percent share, respectively, of total 

41 U.S. electricity generation (EIA 2014). Using these percent shares for the purchased power 

42 alternative, the NRC staff estimates 7.7 million t (6.9 million MT) per year of CO2e will be 

43 emitted. However, GHG emissions may be greater or less than this estimate and will depend 

44 on the technology from which the purchased power comes.
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1 Summary of GHG Emissions From the Proposed Action and Alternatives

2 Table 4–22 presents the direct uncontrolled GHG emissions from operation of the proposed 

3 action and alternatives. GHG emissions from the proposed action (continued operation at 

4 Byron) and the new nuclear alternative would be lowest. GHG emissions for IGCC, NGCC, 

5 combination, and purchased power alternatives are higher than those for the proposed action 

6 and a new nuclear alternative by several orders of magnitude. GHG emissions for purchased 

7 power are expected to be greater than the NGCC alternative, but less than the IGCC 

8 alternative.

9 Table 4–22. Direct Uncontrolled GHG Emissions From Operation of the Proposed Action 

10 and Alternatives

Technology CO2e (MT/year)

Byron Station continued operation 1.363×103

New Nuclear 1.363×103

IGCC 13.0×106

NGCC 7.2×106

Combination (a) 1.0×106

Purchased Power(b) 6.9×106

(a) Only NGCC portion of GHG emissions

(b) Assumed air emissions were estimated by assuming that purchased-power coal accounted for 37 percent share, 

natural gas a 30 percent share, nuclear a 19 percent share, and renewable a 14 percent share of electricity 

generation.

11 4.15.3.2 Climate Change Impacts to Resource Areas

12 Climate change is the decades or longer change in climate measurements (temperature, 

13 precipitation, etc.) that has been observed on a global, national, and regional level (EPA 2012a; 

14 Melillo et al. 2014; Solomon et al. 2007). Climate change can vary regionally, spatially, and 

15 seasonally depending on local, regional, and global factors. Just as the regional climate differs 

16 throughout the world, the impacts of climate change can vary between locations.

17 On a global level, from 1901 to 2011, average surface temperatures have risen at a rate of 

18 0.08°C (0.14 °F) per decade, and total annual precipitation has increased at an average rate of 

19 2.3 percent per decade (EPA 2012a). The observed global change in average surface 

20 temperature and precipitation has been accompanied by an increase in sea surface 

21 temperatures, a decrease in global glacier ice, increase in sea level, and changes in extreme 

22 weather events. Such extreme events include an increase in frequency of heat waves, heavy 

23 precipitation, and minimum and maximum temperatures (EPA 2012a; Karl et al. 2009; 

24 Melillo et al. 2014; Solomon et al. 2007).

25 In the United States, the U.S. Global Change Research Program (USGCRP) reports that from 

26 1895 to 2012, average surface temperature has increased by 1.3 °F to 1.9°F (0.72 to 1.06°C) 

27 and since 1900, average annual precipitation has increased by 5 percent (Melillo et al. 2014). 

28 On a seasonal basis, warming has been the greatest in winter and spring. From 1895 to 2001, 

29 an increase in the length of the freeze-free season, the period between the last occurrence of 

30 0 °C (32°F) in the spring and first occurrence of 0°C (32°F) in the fall has been observed for the 

31 contiguous United States; between 1991 and 2011 the average freeze-free season was 10 days 
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1 longer than between 1901 and 1960 (Melillo et al. 2014). Since the 1970s, the United States

2 has warmed at a faster rate as the average surface temperature rose at an average rate of 0.17 

3 to 0.25 °C (0.31 to 0.45 °F) per decade. In addition, the year 2012 was the warmest on record 

4 (Melillo et al. 2014). Observed climate-related changes in the United States include increases 

5 in the frequency and intensity of heavy precipitation, earlier onset of spring snowmelt and runoff, 

6 rise of sea level in coastal areas of the United States, increase in occurrence of heat waves, 

7 and a decrease in occurrence of cold waves (EPA 2012a; Karl et al. 2009; Kunkel et al. 2013b; 

8 Melillo et al. 2014).

9 Temperature data indicate that the Midwest region, where Byron is located, experienced a 

10 0.06 °C (0.11 °F) per decade increase in annual mean temperature during the 1900 to 2010 

11 period (Kunkel et al. 2013a). Temperature data for the recent past indicate an increased rate of 

12 warming for the Midwest: 0.12 °C (0.22 °F) per decade for the 1950 to 2010 time period and a 

13 0.26 °C (0.47 °F) temperature increase for the 1979 to 2010 time period. Average annual 

14 precipitation data for the Midwest exhibit an increasing trend of 0.31 in. per decade for the 

15 long-term period (1895 to 2011) (Kunkel et al. 2013a). Precipitation data over the 1958 to 2007 

16 period exhibit clear trends toward more very-heavy precipitation events (defined as the heaviest 

17 1 percent of all daily events) for the Nation as a whole, and particularly in the Northeast and 

18 Midwest. Temperature and precipitation trends were analyzed for the period of 1961 to 2012 at 

19 the Rockford Airport (NCDC 1984, 2013). Although there are large year-to-year variations, a 

20 clear upward trend in temperature and a downward trend in precipitation are observed. At 

21 Byron, for the 1973 to 2013 period, an upward trend in ambient annual average temperature 

22 has also been observed (Exelon 2013b).

23 Future GHG emission concentration and climate models are commonly used to project possible 

24 climate change. Climate models indicate that over the next few decades, temperature 

25 increases will continue due to current GHG emissions concentrations in the atmosphere (Melillo 

26 et al. 2014). Over the longer term, the magnitude of temperature increases and climate change 

27 effects will depend on both past and future GHG emission scenarios (Karl et al. 2009; 

28 Melillo et al. 2014; Solomon et al. 2007). Climate models project a continued increase in global 

29 surface temperatures, more frequent and long-lasting heat waves, continued increase in sea 

30 level, continued decline in arctic sea ice, an increase in heavy precipitation events, and an 

31 increased frequency of severe droughts.

32 For the license renewal period of Byron, climate model simulations (between 2021 and 2050 

33 relative to the reference period (1971 to 1999)) indicate an increase in annual mean 

34 temperature in the Midwest region from 2.5 to 3.5°F (1.5 to 2.1°C) (Kunkel et al. 2013a). The 

35 predicted increase in temperature during this time period occurs for all seasons with the largest 

36 increase occurring in the summertime (June, July, and August). Models project an increase in 

37 summertime mean temperatures of 3 °F (1.6 °C); however, climate models displayed a wide 

38 range in summertime temperatures, ranging from an increase of 1.5 to 5.5 °F (0.76 to 2.98 °C)

39 (Kunkel et al. 2013a). Climate model simulations (for the time period 2021 to 2050) suggest 

40 spatial differences in annual mean precipitation changes for the Midwest with northern areas 

41 experiencing an increase in precipitation and the southern areas experiencing a decrease in 

42 precipitation. For Illinois, the models indicate a 0 to 3 percent increase in annual mean 

43 precipitation with fall, winter, and spring seasons experiencing precipitation change increases 

44 and the summer season experiencing a decrease in precipitation. However, these changes in 

45 precipitation were not significant and the models indicate changes that are less than normal 

46 year-to-year variations (Kunkel et al. 2013a). While future regional changes in precipitation are 

47 difficult to predict, the USGCRP reports that storm tracks are expected to shift northward, 

48 increases in heavy precipitation events will continue, the number of dry days between rainfalls 

49 will increase, and an increase in drought are expected (Melillo et al. 2014).
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1 Changes in climate have broader implications for public health, water resources, land use and 

2 development, and ecosystems. For instance, changes in precipitation patterns and increase in 

3 air temperature can affect water availability and quality, distribution of plant and animal species, 

4 and land-use patterns and land cover, which can in turn affect terrestrial and aquatic habitats. 

5 The following sections discuss how future climate change may impact air quality, water

6 resources, land use, terrestrial resources, aquatic resources, and human health in the region of 

7 interest for Byron Station. Although there is uncertainty in the exact future climate change 

8 scenario, the discussions provided below demonstrate the potential implications of climate 

9 change on resources.

10 Air Quality

11 Air pollutant concentrations result from complex interactions between physical and dynamic 

12 properties of the atmosphere, land, and ocean. The formation, transport, dispersion, and 

13 deposition of air pollutants depend in part on weather conditions (Parry et al. 2007). Air 

14 pollutant concentrations are sensitive to winds, temperature, humidity, and precipitation 

15 (EPA 2009b). Hence, climate change can impact air quality as a result of the changes in 

16 meteorological conditions.

17 Ozone has been found to be particularly sensitive to climate change (EPA 2009a; Melillo 

18 et al. 2014; Parry et al. 2007). Ozone is formed as a result of the chemical reaction of nitrogen 

19 oxides and VOCs in the presence of heat and sunlight. Sunshine, high temperatures, and air 

20 stagnation are favorable meteorological conditions to higher levels of ozone (EPA 2009a; Parry 

21 et al. 2007). The emission of ozone precursors also depends on temperature, wind, and solar 

22 radiation (Parry et al. 2007); both nitrogen oxide and biogenic VOC emissions are expected to 

23 be higher in a warmer climate (EPA 2009a). Warmer climate and weaker air circulation are

24 conducive to higher ozone levels. Regional air quality modeling indicates that the northern 

25 regions of the United States can experience an increase in ozone concentration by the year 

26 2050 (Tagaris et al. 2009). However, air quality projections (particularly ozone and particulate 

27 matter with aerodynamic diameters of 2.5 μm or less (PM2.5)) are uncertain and indicate that 

28 concentrations are driven primarily by emissions rather than by physical climate change 

29 (Stocker et al. 2013). The combination of higher temperatures, stagnant air masses, sunlight, 

30 and emissions of precursors may make it difficult to meet ozone NAAQS (Karl et al. 2009 ).

31 Land Use

32 Anthropogenic land use is both a contributor to climate change as well as a receptor of climate 

33 change impacts (Dale 1997). As described previously in this section, the Midwest will likely 

34 experience rising temperatures and heavier precipitation events during the proposed license 

35 renewal period. Agriculture (the major land use in the vicinity of Byron) and growing urban 

36 areas will further exacerbate these changes by continuing to inhibit natural ecosystem functions 

37 that could moderate climate change effects. For instance, air temperatures and near-surface 

38 moisture levels change in areas where natural vegetation is converted to agricultural use, and in 

39 the Midwest, higher temperatures have been observed as a result of converting land to 

40 agricultural use (Melillo et al. 2014). The USGCRP (Melillo et al. 2014) indicates that land use 

41 changes, such as the continued expansion of urban areas, paired with climate change effects, 

42 such as heaver precipitation events, can exacerbate climate change effects, including reduced 

43 water filtration into the soil and increased surface runoff. While anthropogenic land uses will 

44 contribute to climate change in these and other ways, land uses will also be affected by climate 

45 change in several ways. For instance, plant winter hardiness zones are likely to shift one-half to 

46 one full zone by the end of the proposed license renewal period (Melillo et al. 2014). This will 

47 affect the ability to grow certain crops as the Midwest will likely contain plants now associated 

48 with the Southeast by the end of the century (Melillo et al. 2014). Water availability will likely 
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1 affect urban areas, which are growing rapidly in the Midwest. This growth will likely lead to 

2 water use conflicts as climate change reduces water availability and the growing population 

3 requires more water.

4 Water Resources

5 Predicted changes in the timing, intensity, and distribution of precipitation would be likely to 

6 result in changes in surface water runoff affecting water availability across the Midwest. As 

7 discussed above, the Midwest may experience increased precipitation during the fall, winter, 

8 and spring. As cited by the USGCRP, the loss of moisture from soils because of higher 

9 temperatures, as is projected for the Midwest, along with evapotranspiration from vegetation, is 

10 likely to increase the frequency, duration, and intensity of droughts across the region into the 

11 future (Karl et al. 2009; Melillo et al. 2014); such conditions can reduce the amount of water 

12 available for surface runoff and streamflow. Runoff and streamflow at a regional scale for the 

13 Midwest region indicate no clear trend during the last half century. However, annual runoff and 

14 river flow are projected to increase in the upper Midwest, and soil moisture has increased in 

15 most seasons in the upper Midwest between 1998 and 2010 (Melillo et al. 2014). Climate 

16 change impacts on groundwater availability depends on basin geology, frequency and intensity 

17 of high-rainfall periods, recharge, soil moisture, and groundwater–surface water interactions 

18 (Melillo et al. 2014). Precipitation and evapotranspiration are key drivers in aquifer recharge. 

19 Although exact responses in groundwater storage and flow to climate change are not 

20 well-understood, recent studies have started to consider the effects that climate change has on 

21 groundwater resources (Melillo et al. 2014).

22 Terrestrial Resources

23 As described above, the Midwest will likely experience rising temperatures and heavier 

24 precipitation events during the proposed license renewal period. As the climate changes, 

25 terrestrial resources will either need to be able to tolerate the new physical conditions or shift 

26 their population range to new areas with a more suitable climate. Scientists currently estimate 

27 that species are shifting their ranges at a rate of between 6.1 to 11 m (20 to 36 ft) in elevation 

28 per decade and 6.1 to 16.9 km (3.8 to 10.5 mi) in latitude per decade (Chen et al. 2011; 

29 Thuiller 2007). While some species may readily adapt to a changing climate, others may be 

30 more prone to experience adverse effects. For example, species whose ranges are already 

31 limited by habitat loss or fragmentation or who require very specific environmental conditions 

32 may not be able to successfully shift their ranges over time. Migratory birds that travel long 

33 distances may also be disproportionately affected because they may not be able to pick up on 

34 environmental cues that a warmer, earlier spring is occurring in the United States while 

35 overwintering in tropical areas. Fraser et al. (2013) found that songbirds overwintering in the 

36 Amazon did not leave their winter sites earlier, even when spring sites in the Eastern 

37 United States experienced a warmer spring. As a result, the songbirds missed periods of peak 

38 food availability. Habitat ranges for forest systems in the Midwest, such as paper birch, balsam 

39 fir, and black spruce, are projected to decline across the Midwest as they shift northward, and 

40 species that are common farther south, such as oaks and pines, will expand their range north 

41 into the Midwest region (Melillo et al. 2014). Special status species and habitats, such as those 

42 that are Federally protected by the ESA, would likely be more sensitive to climate changes 

43 because these species’ populations are already experiencing threats that are endangering their 

44 continued existence throughout all or a significant portion of their ranges. Climate changes 

45 could also favor nonnative, invasive species and promote population increases of insect pests 

46 and plant pathogens, which may be more tolerant to a wider range of climate conditions.
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1 Aquatic Resources

2 The potential effects of climate change, whether from natural cycles or manmade activities 

3 could result in changes that would affect aquatic resources in the Rock River. Raised air 

4 temperatures could result in higher water temperatures in the Rock River and its tributaries. 

5 Higher water temperatures would increase the potential for thermal effects on aquatic biota and 

6 could exacerbate existing environmental stressors, such as excess nutrients, sedimentation, 

7 and lowered dissolved oxygen associated with eutrophication (Melillo et al. 2013). The Midwest 

8 will likely experience increased frequency of extreme rainfall events, which will cause erosion 

9 and could lead to a decline in water quality (Melillo et al. 2014). Species that require cleaner 

10 waters, such as freshwater mussels, could experience further population declines. The 

11 USGCRP (Melillo et al. 2014) predicts habitat loss and local extinctions of fish and other aquatic 

12 species throughout the United States from the combined effects of water withdrawal and climate 

13 change. Shifts in species’ assemblages and distributions are also likely as climate change 

14 continues (Melillo et al. 2014), and these shifts could alter the balance of the aquatic community 

15 in the Rock River. As discussed above under “Terrestrial Resources,” special status species, 

16 such as those that are Federally protected under the ESA, would be more sensitive to climate 

17 changes. Invasions of nonnative species that thrive under a wide range of environmental 

18 conditions could further disrupt the current composition of aquatic communities (NRC 2013a).

19 Historic and Cultural Resources

20 Increases in river and lake water levels because of changes in meteorological conditions due to 

21 climate change could result in the loss of historic and cultural resources from flooding, erosion, 

22 or inundation. Due to water-level changes, some resources could be lost before they could be 

23 documented or otherwise studied. However, the limited extent of climate change that may 

24 occur during the 20-year license renewal term would not likely result in any significant loss of 

25 historic and cultural resources at Byron.

26 Socioeconomics

27 Rapid changes in climate conditions could have an impact on the availability of jobs in certain 

28 industries. For example, tourism and recreation are major job creators in some regions, 

29 bringing billions of dollars to regional economies. Across the Nation, fishing, hunting, and other 

30 outdoor activities make important economic contributions to rural economies and are also a part 

31 of the cultural tradition. A changing climate would mean reduced opportunities for some 

32 activities in some locations and expanded opportunities for others. Hunting and fishing 

33 opportunities could also change as animals’ habitats shift and as relationships among species 

34 are disrupted by their different responses to climate change (Melillo et al. 2014). 

35 Water-dependent recreation could also be affected (Karl et al. 2009;). The USGCRP reports 

36 that increasing heat and humidity associated with climate change in parts of the Midwest region 

37 by the year 2050 could create unfavorable conditions for summertime outdoor recreation and 

38 tourism activity (Melillo et al. 2014). However, the limited extent of climate change that may 

39 occur during the 20-year license renewal term would not be likely to cause any significant 

40 changes in socioeconomic conditions in the vicinity of Byron.

41 Human Health

42 Increasing temperatures due to changes in climate conditions could have an impact on human 

43 health. However, changes in climate conditions that may occur during the license renewal term 

44 will not result in any change to the impacts discussed in Section 4.11 from Byron’s radioactive 

45 and nonradioactive effluents.
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1 Environmental Justice

2 Rapid changes in climate conditions could disproportionately affect minority and low-income 

3 populations. The USGCRP (Karl et al. 2009) indicates that “infants and children, pregnant 

4 women, the elderly, people with chronic medical conditions, outdoor workers, and people living 

5 in poverty are especially at risk from a variety of climate-related health effects.” Examples of 

6 these effects include increased heat stress, air pollution, extreme weather events, and diseases 

7 carried by food, water, and insects. The greatest health burdens related to climate change are 

8 likely to fall on the poor, especially those lacking adequate shelter and access to other 

9 resources such as air conditioning. Elderly people on fixed incomes, who are more likely to be 

10 poor, are more likely to have debilitating chronic diseases or limited mobility. In addition, the 

11 elderly have a reduced ability to regulate their own body temperature or sense when they are 

12 too hot. According to the USGCRP (Karl et al. 2009), they “are at greater risk of heart failure, 

13 which is further exacerbated when cardiac demand increases in order to cool the body during a 

14 heat wave.” The USGCRP study also found that people taking medications, such as diuretics 

15 for high blood pressure, have a higher risk of dehydration (Karl et al. 2009). The USGCRP 

16 (Melillo et al. 2014) study reconfirmed the previous report findings regarding the risks of climate 

17 change on low-income populations, and also warns that climate change could affect the 

18 availability and access to local plant and animal species, thus impacting the people that have 

19 historically depended on them for food or medicine (Melillo et al. 2014). However, due to the 

20 amount of expected change in the environment during the 20-year license renewal term, 

21 minority and low-income populations at Byron are not likely to experience disproportionately 

22 high and adverse impacts from climate change.

23 4.16 Cumulative Impacts of the Proposed Action

24 The NRC staff considered potential cumulative impacts in the environmental analysis of 

25 continued operation Byron during the 20-year license renewal period. Cumulative impacts may 

26 result when the environmental effects associated with the proposed action are overlaid or added 

27 to temporary or permanent effects associated with other past, present, and reasonably 

28 foreseeable actions. Cumulative impacts can result from individually minor, but collectively 

29 significant, actions taking place over a period of time. It is possible that an impact that may be 

30 SMALL by itself could result in a MODERATE or LARGE cumulative impact when considered in 

31 combination with the impacts of other actions on the affected resource. Likewise, if a resource 

32 is regionally declining or imperiled, even a SMALL individual impact could be important if it 

33 contributes to or accelerates the overall resource decline.

34 For the purposes of this cumulative analysis, past actions are those before the receipt of the 

35 license renewal application. Present actions are those related to the resources at the time of 

36 current operation of the power plant, and future actions are those that are reasonably 

37 foreseeable through the end of plant operation, including the period of extended operation. 

38 Therefore, the analysis considers potential impacts through the end of the current license terms 

39 as well as the 20-year renewal license term. The geographic area over which past, present, 

40 and reasonably foreseeable actions would occur depends on the type of action considered and 

41 is described below for each resource area.

42 To evaluate cumulative impacts, the incremental impacts of the proposed action, as described 

43 in Sections 4.2 to 4.15, are combined with other past, present, and reasonably foreseeable 

44 future actions regardless of what agency (Federal or non-Federal) or person undertakes such 

45 actions. The NRC staff used the information provided in Exelon’s ER; responses to requests for 

46 additional information; information from other Federal, State, and local agencies; scoping

47 comments; and information gathered during the visits to the Byron site to identify other past, 
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1 present, and reasonably foreseeable actions. To be considered in the cumulative analysis, the 

2 NRC staff determined if the project would occur within the noted geographic areas of interest 

3 and within the period of extended operation, was reasonably foreseeable, and if there would be 

4 a potential overlapping effect with the proposed project. For past actions, consideration within 

5 the cumulative impacts assessment is resource- and project-specific. In general, the effects of 

6 past actions are included in the description of the affected environment in Chapter 3, which 

7 serves as the baseline for the cumulative impacts analysis. However, past actions that continue 

8 to have an overlapping effect on a resource potentially affected by the proposed action are 

9 considered in the cumulative analysis.

10 Other actions and projects identified during this review and considered in the NRC staff’s 

11 analysis of the potential cumulative effects are described in Appendix E. Not all actions or 

12 projects listed in Appendix E are considered in each resource area due to the uniqueness of the 

13 resource and its geographic area of consideration.

14 4.16.1 Air Quality and Noise

15 This section addresses the direct and indirect effects of license renewal on air quality and noise 

16 when added to the aggregate effects of other past, present, and reasonably foreseeable future 

17 actions. As described in Section 4.3.1, the incremental impacts on air quality and noise levels 

18 from the proposed license renewal would be SMALL.

19 4.16.1.1 Air Quality

20 The geographic area considered in the cumulative air quality analysis is the county of the 

21 proposed action as air quality designations for criteria air pollutants are generally made at the 

22 county level. Counties are further grouped together based on a common airshed—known as an 

23 Air Quality Control Region (AQCR)—to provide for the attainment and maintenance of the 

24 NAAQS. The Byron site is located in Ogle County, Illinois, which is part of Rockford (Illinois)–

25 Janesville–Beloit (Wisconsin) Interstate AQCR (40 CFR 81.71).

26 As noted in Section 3.3.2, EPA regulates six criteria pollutants under the NAAQS, including 

27 carbon monoxide, lead, nitrogen dioxide, ozone, sulfur dioxide, and PM. With regard to the 

28 NAAQS criteria pollutants, Ogle County is designated as an attainment/unclassifiable area for 

29 all criteria pollutants (40 CFR 81.314).

30 Criteria pollutant air emissions from the Byron site are presented in Section 3.3.2; these 

31 emissions are from permitted sources including standby emergency diesel generators, auxiliary 

32 boilers, AFW pumps, SX makeup water pumps, a fire pump, and two natural draft and 

33 two mechanical draft cooling towers (Exelon 2013b). Since there will be no 

34 refurbishment-related activities, the NRC staff expects similar emissions during the license 

35 renewal period. Therefore, cumulative changes to air quality in Hamilton County and AQCR 

36 would be the result of changes to present-day emissions as well as future projects and actions 

37 within the county.

38 Appendix E provides a list of present and reasonably foreseeable projects that could contribute 

39 to cumulative impacts to air quality. For example, there are limited industrial facilities, including 

40 two landfills, one small hydroelectric power plant, and several water supply and treatment 

41 facilities, within the 80-km (50-mi) radius of Byron Station, and IEPA regulates air emissions 

42 through air permits. Continued air emissions from existing projects and actions listed in 

43 Appendix F as well as proposed new source activities would contribute to air emissions in Ogle 

44 County.

45 At Byron Station, about 60 staff could be added to implement aging management programs and 

46 temporary workforces on staggered 18-month refueling cycles (Exelon 2013a). Additionally, 
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1 Units 1 and 2 reactor pressure vessel head replacement (assumed to occur during a 7-day 

2 period with 340 additional workers) and Unit 2 SG replacement (estimated to require an 

3 additional 500 workers for 90 days) may occur at Byron. The main contributors to air quality 

4 impacts associated with these activities would be fugitive dust generation from construction 

5 activities, work to open containment to replace the SGs and related equipment, and exhaust 

6 emissions from motorized equipment and vehicles of temporary workers. The additional vehicle 

7 air emissions resulting from the additional workforce for SG replacement activities (used as the 

8 bounding conditions for this analysis) would be temporary and are estimated to result in an 

9 additional 3.3 t (3.0 MT) of VOCs, 9.8 t (8.9 MT) of nitrogen oxides, 0.04 t (0.04 MT) of sulfur 

10 dioxide, and 0.40 t (0.36 MT) of PM2.5 (direct emissions) being emitted, which do not exceed the 

11 de minimis levels of 100 t per year set forth in 40 CFR 93.153(b). Therefore, the additional 

12 emissions resulting from these activities at Byron are expected to be minor.

13 Development and construction activities associated with regional growth of housing, business, 

14 and industry, as well as associated vehicular traffic, will also result in additional air emissions. 

15 Project timing and location, which are difficult to predict, affect cumulative impacts to air quality. 

16 However, permitting and licensing requirements, efficiencies in equipment, cleaner fuels, and 

17 various mitigation measures can be used to minimize cumulative air quality impacts. 

18 Accordingly, cumulative impacts on air quality are expected to be minor and remain minor 

19 during the license renewal term.

20 Climate change can impact air quality as a result of changes in meteorological conditions. Air 

21 pollutant concentrations are sensitive to winds, temperature, humidity, and precipitation 

22 (EPA 2009b). As discussed in Section 4.15.3.2, ozone levels have been found to be particularly 

23 sensitive to climate change influences (EPA 2009a; Solomon et al. 2007). Sunshine, high 

24 temperatures and air stagnation are favorable meteorological conditions leading to higher levels 

25 of ozone (EPA 2009a; Solomon et al. 2007). The combination of higher temperatures, stagnant 

26 air masses, sunlight, and emissions of precursors may make it difficult to meet ozone NAAQS 

27 (Karl et al. 2009). States, however, must continue to comply with the CAA and ensure air 

28 quality standards are met.

29 4.16.1.2 Noise

30 Section 3.3.3 presents a summary of noise sources at Byron and site vicinity. Noise emission 

31 sources from Byron include cooling towers, ventilation supply and exhaust fans, transformers, 

32 intake water pumps, transmission lines, infrequent relief valves, onsite vehicle traffic (commuter 

33 or delivery trucks), and shooting range activities (Exelon 2013b).

34 Noise is usually considered as a local problem. Noise levels in the vicinity of a nuclear power 

35 plant could increase from planned activities associated with urban, industrial, and commercial 

36 development. The magnitude of cumulative impacts depends on the nuclear plant’s proximity to 

37 other noise sources. A 3-dBA change in sound level is considered barely discernible, as 

38 discussed in Section 3.3.3. A 3-dBA increase would occur with the placement of another 

39 identical source over an existing source, (e.g., double the traffic volume). Ongoing or 

40 foreseeable future projects in and around the Byron Station as identified in Appendix F would 

41 increase noise levels only in the vicinity of their noise sources, and combined noise levels are 

42 not expected to be high enough to cause noise issues. For instance, activities at the Byron site 

43 related to SG replacement or reactor pressure vessel head replacement, if they occur, would 

44 increase noise levels as a result of construction activities related to the storage facility, 

45 motorized equipment, and increased vehicles. Construction equipment, for instance, can result 

46 in noise levels in the range of 85 to 90 dBA; however, noise levels attenuate rapidly with 

47 distance such that at half a mile distance from construction equipment, noise levels can drop to 

48 51 to 61 dBA (NRC 2002). Additional noise from construction activities would be temporary and 
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1 intermittent and the majority of work activities would occur inside of buildings. The additional 

2 noise sources are not expected to be audible beyond the site boundary. Therefore, 

3 contributions to noise levels from future actions are limited by projects in the vicinity of Byron. 

4 Accordingly, cumulative impacts on noise levels are expected to be minor and remain minor

5 during the license renewal term.

6 4.16.1.3 Conclusion

7 Past, present, and reasonably foreseeable future activities exist in the geographic areas of 

8 interest (local for noise, local and regional for criteria pollutants) that could affect air quality and 

9 noise resources. However, the incremental contribution of impacts on air quality and noise 

10 resources from plant operations at Byron Station would be minimal. The NRC staff concludes 

11 that cumulative impacts from other past, present, and reasonably foreseeable future actions on 

12 air quality and noise resources in the geographic areas of interest would be SMALL.

13 4.16.2 Geology and Soils

14 This section addresses the direct and indirect effects of license renewal on geology and soils 

15 when added to the aggregate effects of other past, present, and reasonably foreseeable future 

16 actions. As noted in Section 2.1.2, Exelon has no plans to conduct refurbishment or 

17 replacement actions, and activities associated with continued operations are not expected to 

18 affect the geologic environment. Ongoing operation and maintenance activities at the Byron site 

19 are expected to be confined to previously disturbed areas, and geologic conditions are not 

20 expected to change during the license renewal term. Any use of geologic materials, such as 

21 aggregates to support operation and maintenance activities, would be procured from local and 

22 regional sources. These materials are abundant in the region, and supplies would be sufficient 

23 for any current or future projects in the area requiring these materials. Thus, the NRC staff 

24 concludes that the cumulative impact of the proposed license renewal of Byron, when combined 

25 with other past, present, and reasonably foreseeable future projects or actions, would be 

26 SMALL on geology and soils. 

27 4.16.3 Water Resources

28 This section addresses the direct and indirect effects of license renewal on surface water and 

29 groundwater when added to the aggregate effects of other past, present, and reasonably 

30 foreseeable future actions. As described in Sections 4.5.1.1 and 4.5.1.2, the incremental 

31 impacts on water resources from continued operations of Byron during the license renewal term 

32 would be SMALL. NRC staff also conducted an assessment of other projects and actions for 

33 consideration in determining their cumulative impacts on water resources (see Appendix F). 

34 The geographic area considered for the surface water resources component of the cumulative 

35 impacts analysis spans the Rock River basin. For groundwater, the geographic area of interest 

36 is comprised of the local groundwater basin relative to the Byron site, the Ironton-Galesville and 

37 Mt. Simon Sandstone aquifers. As such, this review focused on those projects and activities 

38 that would (1) withdraw water from or discharge wastewater to the Rock River basin or (2) use 

39 groundwater from the Ironton-Galesville and Mt. Simon Sandstone aquifers.

40 4.16.3.1 Surface Water Resources

The Rock River basin drains an area of approximately 10,915 square miles (mi2 41 ) (17,566 square 

kilometers (km2 42 )). Approximately half of the basin is in northern Illinois while the remaining half 

43 is in south-central Wisconsin (Section 3.5.1.1, Figure 3–8). From Wisconsin, the river drains 

44 southwestward through Illinois and into the Mississippi River. The landscape and soils have a 

45 substantial influence on the hydrology of the Rock River basin and the landscape of the Rock 
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1 River basin is quite varied. The landscape includes dissected, hilly terrain, rolling hills, and a 

2 flat outwash plain. There is also considerable spatial variability in the permeability and drainage 

3 characteristics of the soils in the basin. However, land use, another important influence of the 

4 hydrology of a drainage basin, is comparatively homogeneous, with more than 85 percent of the 

5 basin in row crops or rural grassland (Knapp and Russell 2004).

6 The total population residing in the Rock River basin in both Wisconsin and Illinois is about 

7 1.7 million people. The two major population centers in the basin are the cities of Rockford, 

8 Illinois, and Madison, Wisconsin. Between 1990 and 2000, the population in the Illinois portion 

9 of the basin rose by approximately 10 percent as a result of growth near the Chicago 

10 metropolitan area. However, the population in the western part of the basin (which includes the 

11 Byron site) experienced little or no increases in population. The eastern part of the basin will 

12 likely continue to see significant population growth in future decades as the margins of the 

13 Chicago metropolitan area continue to expand (Knapp and Russell 2004).

14 Prior to European settlement, the land cover in the Rock River basin was a mixture of open 

15 woodland interspersed with short- and tall-grass prairie. The Rock River basin also had 

16 abundant wetlands, lakes, and large marshes. Today, the only remaining large marsh in the 

17 watershed is the Horicon Marsh, near the headwaters of the Rock River in northern Dodge 

18 County, Wisconsin. It has been designated a “wetland of international importance”. Agriculture 

19 (including cultivation, the removal and drainage of wetland areas, stream channelization, and 

20 deforestation) has had a large impact on the basin. Most of these major modifications to the 

21 landscape occurred in the late 1800s, prior to the onset of stream gaging activities; thus, the 

22 large-scale effects of these modifications on stream flow hydrology were not quantitatively 

23 measured (IEPA 2006; Knapp and Russell 2004).

24 There are seven low-head channel dams on the Rock River in Illinois. These dams originally 

25 were built in the mid-1800s to early 1900s and are typically 10 to 15 ft (3 to 5 m) high. For the 

26 most part, these small reservoirs do not have a noticeable impact on stream flows in the Rock 

27 River. From the 1960s through 1999, average stream flow rates for the Rock River in Illinois 

28 have increased. These increases appear to be most directly related to increases in the average 

29 precipitation over the Rock River basin (IDNR 1998a, 2001).

30 In Illinois, the Rock River is not used as a source of public water or for navigation 

31 (Exelon 2013a). Other than for thermoelectric power generation, most water in the basin used 

32 for public, commercial, and industrial purposes is obtained from groundwater (Dziegielewski 

33 et al. 2005; IEPA 2006). Much of the water obtained from groundwater is eventually discharged 

34 into streams as treated wastewater, which adds additional water to the Rock River. 

35 Surface water from the Rock River in Illinois has been able to support ongoing demands and will 

36 likely be sufficient through the license renewal term based on current projections. Future water 

37 demand (both groundwater and surface water) in the Illinois counties within the Rock River 

38 basin is projected to increase by about 10 percent from 2000 to 2025. Most of this projected 

39 demand is for thermoelectric generation near the southern end of the river in the County of Rock 

40 Island. The Byron plant is located in Ogle County. In Ogle County, water demand from either 

41 surface water or groundwater is projected to increase by only a small amount for all types of 

42 water uses (including thermoelectric generation, public supply, commercial, and industrial). 

43 From 2005 to 2025, water demand in Ogle County is projected to increase by about 2 percent. 

44 This is a 2.1 mgd (7,900 cubic meters per day) increase above 2000 water use (Dziegielewski 

45 et al. 2005).

46 As described in Section 4.15.3.2, future climatic changes are anticipated to result in increased 

47 precipitation overall across the region including an increase in heavy-precipitation events, which 

48 in turn would tend to result in increased runoff and flow over the headwaters of the Rock River. 
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1 If future water demand increases through the period of extended operation (up to 2046) are 

2 similar to the projected demand increases between 2005 and 2025, then surface water supplies 

3 appear to be abundant enough to meet the reasonably foreseeable demand. Consumptive 

4 water use from continued Byron operations will continue to be a very small percentage of the 

5 overall flow of the Rock River.

6 Within Illinois, the surface water quality of the Rock River watershed is judged to be generally 

7 good. The primary causes of water quality problems are siltation, suspended solids, 

8 hydrologic/habitat modifications, and nutrients largely attributed to agriculture, with some 

9 contribution from urban runoff (IEPA 1996). It is reasonable to anticipate that water 

10 quality-based limits imposed by NPDES permits on wastewater discharges from Byron and on 

11 other industrial facilities will continue to maintain or improve ambient surface water quality in

12 the Rock River. 

13 4.16.3.2 Groundwater Resources

14 Groundwater resources at the site are described in Section 3.5.2. Byron has not impacted and 

15 is not reasonably expected to impact the quality of groundwater in any aquifers that are a 

16 current or potential future source of water for offsite users. Byron consumes groundwater from

17 the Ironton-Galesville and Mt. Simon Sandstone aquifers. Because of its depth, the Mt. Simon 

18 Sandstone Aquifer is not used as a source of water by local wells. The nearest consumer of 

19 Ironton-Galesville and Mt. Simon Sandstone Aquifer groundwater is the City of Byron, which is 

20 6.4 km (4 mi) northwest of the site (Exelon 2013a). Groundwater modeling of the impact of 

21 pumping the site groundwater wells at high volumes for an extended period of time did not show 

22 any discernible impact on the City of Byron wells (Exelon 2013a).

23 As discussed in Section 4.15.3, the water demand in Ogle County for all types of water use 

24 (including thermoelectric generation, public supply, commercial, and industrial) is projected to 

25 increase by only a small amount. Future climatic changes are not anticipated to result in 

26 decreased groundwater recharge and the availability of groundwater resources. If future water 

27 demand increases through the period of licensing (up to 2046) are similar to the projected 

28 demand increases between 2005 and 2025, then groundwater supplies appear to be abundant 

29 enough to meet reasonably foreseeable demand.

30 4.16.3.3 Conclusion

31 The Byron facility has not impacted and is not expected to impact the quality of groundwater in 

32 any aquifers that are a current or potential future source of water for offsite users, and 

33 groundwater supply is abundant enough to meet reasonably foreseeable demand. 

34 Consumptive surface water use from continued Byron operations will continue to be a very 

35 small percentage of the overall flow of the Rock River, and ongoing and future surface water 

36 demands by users are expected to be supported. Surface water discharges to the Rock River 

37 by Byron and other industrial users will be monitored and kept at acceptable limits via NPDES

38 permits. Considering ongoing activities and reasonably foreseeable actions, the NRC staff 

39 concludes that cumulative impact of the proposed license renewal when combined with other 

40 past, present, and reasonably foreseeable future activities would be SMALL on surface water 

41 and groundwater use and quality.

42 4.16.4 Terrestrial Resource

43 This section addresses past, present, and future actions that could result in cumulative impacts 

44 on the terrestrial species and habitats described in Section 3.6. For purposes of this analysis, 

45 the geographic area considered in the evaluation includes the Byron site. The baseline for this 

46 assessment is the condition of the resource without action (i.e., the no-action alternative). 
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1 Section 4.6 of this SEIS concludes that the impact from the proposed license renewal would not 

2 noticeably alter the terrestrial environment and would be SMALL.

3 4.16.4.1 Historic Conditions

4 Section 3.6 discusses the ecoregions in which the Byron site lies, including the central 

5 U.S. Plains and the central Corn Belt Plains. Gently rolling smooth plains, irregular plains, and 

6 shallow stream valleys characterize much of the area. The native landscape of the ecoregion 

7 was composed of bluestem prairie communities and oak–hickory forests, but has mostly been 

8 replaced by corn and soybean agriculture. Agricultural lands are the predominant land cover in 

9 the ecoregion at 75.3 percent, followed by developed land (11.6 percent), and forests 

10 (9.3 percent). Although developed land is less prominent than agricultural land, from 1973 to 

11 2000, the percent of developed land has increased 2.4 percent, while the percent of agricultural 

12 land and forested land has decreased (Karstensen et al. 2013).

13 Approximately 538 ac (218 ha) total of the Byron site was disturbed during the construction of 

14 Byron Station (30 percent). Of the Byron site (840 ac (340 ha)), 47 percent has been leased for 

15 agricultural use. This land is considered disturbed because most of it is tilled. The remaining 

16 23 percent (404 ac (163 ha)) of Byron is undisturbed land. The terrestrial habitats on the 

17 undeveloped portions of the site have not changed significantly since Byron’s construction

18 (Exelon 2013b). 

19 4.16.4.2 Urbanization

20 As the region surrounding the Byron site becomes more developed, habitat fragmentation will 

21 increase. Species that require larger ranges, especially predators, will likely suffer reductions in 

22 their populations. Herbivores will experience less predation pressure and their populations will 

23 likely increase. Edge species will benefit from fragmentation, while species that require interior 

24 forest or swamp habitat will likely suffer.

25 4.16.4.3 Agricultural Runoff

26 Within Ogle County, 89 percent of land is used for agriculture. The major crops grown in Ogle 

27 County are corn and soybeans. Wheat, oats, and hay are also grown (Exelon 2013a). 

28 Livestock raised in Ogle County include cattle and hogs (Exelon 2004). The 2000 National 

29 Water Quality Inventory reported that agricultural nonpoint source pollution accounted for the 

30 second largest source of impairments to wetlands (EPA 2002). Fertilizers and pesticides can 

31 affect wetlands and bottomlands in a number of ways. Because wetlands and bottomlands are 

32 often at lower elevation than surrounding land, these habitats receive much of the runoff first, 

33 and that runoff persists because it is unable to drain to lower ground. This can result in 

34 bioaccumulation of pollutants and changes to species composition and abundance. Species 

35 that rely on wetlands, such as birds and amphibians, are more sensitive to these environmental 

36 stressors than other wildlife.

37 4.16.4.4 Park and Conservation Areas

38 In Ogle County, the Lowden-Miller State Forest and the adjacent Castle Rock State Park are 

39 both designated Important Bird Areas and contain high-quality terrestrial habitats. Together, 

40 this 4,225-ac (1,710-ha) area provides some of the most diverse terrestrial habitats in the Upper 

41 Rock River Basin. This State-protected forest will continue to provide valuable habitat to native 

42 wildlife and migratory birds during the proposed license renewal period. As habitat 

43 fragmentation resulting from various types of nearby development increases, these areas will 

44 become ecologically more important because they provide large and diverse areas of natural 

45 habitat.
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1 4.16.4.5 Unit 2 Steam Generator Replacement

2 As discussed in Section 2.1.2, Exelon determined that no major refurbishment or replacement 

3 activities were needed to support the operation of Byron beyond the end of the existing 

4 operating license (Exelon 2013a). However, in its ER, Exelon (2013a) indicated that it may 

5 perform a replacement of Unit 2’s SGs during the period of extended operation. Since the 

6 Unit 2 SG replacement is not necessary to enter the period of extended operation, the NRC staff

7 is considering this action as a cumulative impact rather than part of the proposed action. 

8 Because Exelon has previously replaced the Unit 1 SGs, Exelon would be able to make use of 

9 previously built infrastructure if the Unit 2 SGs were to be replaced. An additional SG storage 

10 facility or expansion of the existing Unit 1 storage facility could be required, but no undisturbed 

11 land would be affected (Exelon 2013a). New SGs would be transported to the site via existing 

12 rail and would not require any road or rail upgrades (Exelon 2013a). Wildlife could experience 

13 temporary increases in noise and traffic to and from the site during the SG replacement period 

14 that could lead to behavioral changes, habitat abandonment, or increased susceptibility to injury 

15 or mortality from vehicle strikes. However, because nuclear plants often pair such activities with 

16 refueling periods, the incremental increase in noise and traffic attributable to the SG

17 replacement would not create measurable impacts on terrestrial wildlife. Terrestrial habitats and 

18 vegetation would be unaffected.

19 4.16.4.6 Conclusion

20 Section 4.6 of this SEIS concludes that the impact from the proposed license renewal would not 

21 noticeably alter the terrestrial environment and would be SMALL. However, as environmental 

22 stressors such as agricultural runoff and residential development continue over the proposed 

23 license renewal term, certain attributes of the terrestrial environment (such as species diversity 

24 and distribution) are likely to noticeably change. The NRC staff does not expect these impacts 

25 to destabilize any important attributes of the terrestrial environment, but instead cause gradual 

26 change, which would allow the terrestrial environment to adapt appropriately. The NRC staff 

27 concludes that the cumulative impacts of the proposed license renewal of Byron and other past, 

28 present, and reasonably foreseeable future projects or actions would result in MODERATE 

29 impacts to terrestrial resources.

30 4.16.5 Aquatic Resources

31 This section addresses the direct and indirect effects of license renewal on aquatic resources 

32 when added to the aggregate effects of other past, present, and reasonably foreseeable future 

33 actions. Section 4.7 of this document finds that the direct and indirect impacts on aquatic 

34 resources from the proposed license renewal when considered in the absence of the aggregate 

35 effects would be SMALL. The cumulative impact is the total effect on the aquatic resources of 

36 all actions taken, no matter who has taken the actions (the second principle of cumulative 

37 effects analysis in CEQ 1997).

38 Two related concepts bound the analysis of cumulative impacts: the timeframe and geographic 

39 extent. The timeframe for cumulative analyses for ecological resources extends far enough into 

40 the past to understand the processes that affect the present resource conditions and to examine 

41 whether and why aquatic resources are stable or unstable, which the NRC definitions of impact 

42 levels require. The timeframe for cumulative impact analysis is more extensive than that for the 

43 direct and indirect impact analysis.

44 The geographic extent considered in this cumulative aquatic resource analysis depends on the 

45 particular cumulative impacts being discussed. Direct and indirect impacts from the Byron site 

46 are limited to the Rock River. During preoperational and operational monitoring, studies 

47 determined that the effects of Byron operations on aquatic resources are effectively confined to 
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1 an area of the Rock River that extends from 300 yards (270 m) upstream of the cooling tower 

2 blowdown discharge point and continues 0.7 mi (1.1 km) downstream of the discharge point (as 

3 discussed in Section 3.7). Fish and other aquatic organisms that occur in this area could travel 

4 upstream or downstream. These species’ movement would be largely prohibited by dams on 

5 the river—the Rockford Dam upstream and the Oregon Dam approximately 5 mi (8 km) 

6 downstream of the Byron site—and thus, direct and indirect effects to aquatic resources that 

7 could result from continued operation of Byron and other actions could not be meaningfully 

8 discerned or described beyond these points. However, projects or actions located beyond this 

9 geographic area could directly or indirectly affect the aquatic resources in this area. This 

10 section focuses on the cumulative effects of such actions.

11 The level of cumulative impacts is measured against a baseline. Consistent with the Council on 

12 Environmental Quality’s (CEQ’s) (1997) NEPA guidance, the term “baseline” pertains to the 

13 condition of the resource without the action, (i.e., under the no-action alternative). Under the 

14 no-action alternative, the plant would shut down and the resource would conceptually return to 

15 its condition without the plant (which is not necessarily the same as the condition before the 

16 plant was constructed). The baseline, or benchmark, for assessing cumulative impacts on 

17 aquatic resources takes into account the preoperational environment as recommended by 

18 EPA (1999b) for its review of NEPA documents.

19 4.16.5.1 Past River Development, Channelization, and Damming

The Rock River basin covers 6,481 mi2 (10,430 km2 20 ) within Illinois, and Ogle County is wholly 

21 contained within the basin. The basin has experienced considerable land use modification 

22 since European settlement, which has affected Rock River aquatic resources. Beginning in the 

23 early 1900s, several swamps in the Rock River basin were drained, and the river was dredged 

24 and channelized for navigation. Seven low-head dams, one of which still operates, were 

25 constructed by the 1930s (Sinclair 1996). These changes have divided certain aquatic biota

26 into localized populations and altered stream flow, quality, and aquatic communities 

27 significantly.

28 4.16.5.2 Energy Development

29 Five nuclear power plant sites with nine operating reactors lie within 50 mi (80 km) of the Byron 

30 site (see Appendix E). Because the effects of these facilities would primarily be limited to the 

31 water body from which they draw cooling water and none of these facilities draw from the Rock 

32 River, the operation of these facilities would not result in cumulative effects to the aquatic 

33 resources affected by Byron operation.

34 The North American Hydro Rockton Plant lies approximately 130 mi (209 km) north of Byron on 

35 the Rock River. This facility began operating in 1929, and the Federal Energy Regulatory 

36 Commission (FERC) has licensed it to operate through August 2023 (NAH 2014). If this 

37 facility’s license is renewed, the renewed term would overlap with Byron’s proposed license 

38 renewal period, which begins in 2024 (Unit 1) and 2026 (Unit 2). Hydroelectric dams are 

39 barriers to fish migration, and the transport of fish, eggs, and larvae through the dams result in 

40 some mortality (Cada 1991; Watters 2000). Dams alter flow regimes and water quality, which 

41 modifies the quality and types of downstream aquatic microhabitats. This facility has likely 

42 contributed to significant changes in aquatic communities in the Rock River and will continue to 

43 do so during the proposed Byron license renewal period if it is relicensed to operate 

44 beyond 2023.

45 The Nelson Energy Center is a combined-cycle facility that is currently under construction in 

46 Rock Falls, Illinois, approximately 26 mi (42 km) southwest of Byron. The facility would begin 

47 operating in 2015, prior to the proposed Byron license renewal period, and would use natural 
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1 gas fuel to operate. The IEPA issued the facility a draft NPDES Permit in August 2013 that 

2 would authorize Invenergy Nelson, LLC, to discharge into the Rock River (IEPA 2013). The 

3 Nelson Energy Center will be located well downriver of Byron and will be hydrologically 

4 separated by the Oregon Dam and the Dixon Dam. Accordingly, the effects of Rock River water 

5 use by each facility would not overlap or would be too small to be meaningfully described or 

6 detected. Air emissions from the Nelson Energy Center will include GHGs such as nitrogen 

7 oxides, carbon dioxide, and methane. Air emissions can have far-reaching consequences 

8 because they cumulatively contribute to climate change. The effects of climate change on 

9 aquatic resources are discussed in Section 4.15.3.2.

10 4.16.5.3 Runoff from Agriculture and Municipal Facilities

11 Illinois river and stream ecosystems historically have had naturally wooded floodplains, which 

12 moderated water temperatures and stabilized stream banks to reduce erosion. Less than 

13 10 percent of land bordering the Rock River remains forested, and much of the floodplains have 

14 been converted to cropland. This has likely contributed to erosion and sedimentation and will 

15 continue to do so during the proposed Byron license renewal period. In 1996, the IEPA rated 

16 67 percent of the Rock River mainstem as “Full Support,” which means that these portions of 

17 the river meet the needs of all designated uses protected by applicable water quality standards 

18 (IDNR 1998b). The IEPA rated the remaining 33 percent of the mainstem as “Partial 

19 Support/Minor Impairment,” which means that the water quality has been impaired, but only to a 

20 minor degree. Suspended solids, phosphorus, and other organic nutrients from agricultural 

21 runoff and municipal discharges were major contributors to this rating.

22 4.16.5.4 Parks and Recreational Areas

23 Several parks and natural areas lie within the vicinity of Byron (see Appendix E) including Castle 

24 Rock State Park, which lies approximately 10 mi (16 km) downstream of the Byron. The 

25 continued preservation of these areas will protect aquatic habitats and as land development 

26 continues, these areas will become ecologically more important because they will provide large 

27 areas of unfragmented natural habitat.

28 4.16.5.5 Conclusion

29 NRC staff concludes that the cumulative impacts on aquatic resources in the Rock River are 

30 MODERATE based on past, present, and reasonably foreseeable future actions. This level of 

31 impact is primarily the result of past river channelization and damming and ongoing runoff and 

32 sedimentation from agriculture. The environmental effects of these actions are clearly 

33 noticeable, but available information on the status of the Rock River aquatic communities does 

34 not indicate that these effects have destabilized any important attribute of the community in the 

35 vicinity of Byron. The incremental, site-specific impact from the continued operation of Byron 

36 during the license renewal period would be minor and not noticeable in comparison to 

37 cumulative impact on the aquatic ecology.

38 4.16.6 Historic and Cultural Resources

39 This section addresses the direct and indirect effects of license renewal on historic and cultural

40 resources when added to the aggregate effects of other past, present, and reasonably 

41 foreseeable future actions. The geographic area considered in this analysis is the APE 

42 associated with the proposed undertaking, as described in Section 3.9.

43 The archaeological record for the region indicates prehistoric and historic occupation of the 

44 Byron site and its immediate vicinity. The construction of Byron resulted in destruction of 

45 cultural resources within the Byron site and surrounding area. Other historic land development 

46 in the vicinity of Byron also resulted in impacts on, and the loss of, cultural resources on the 
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1 Byron site and its immediate vicinity. However, there remains the possibility for additional 

2 historic or cultural resources to be located within the Byron site. The present and reasonably 

3 foreseeable projects which could affect these resources reviewed in conjunction with license 

4 renewal are noted in Appendix F of this document. Direct impacts would occur if historic and 

5 cultural resources in the APE were physically removed or disturbed. Indirect visual or noise 

6 impact could occur from new construction or maintenance. The following projects are located 

7 within the geographic area considered for cumulative impacts:

8 • Unit 2 SG replacement, 

9 • Units 1 and 2 reactor pressure vessel head replacement, and

10 • future urbanization in the immediate vicinity of Byron. 

11 As described in Section 4.9, no cultural resources would be adversely affected by Byron Units 1 

12 and 2 license renewal activities as no associated changes or ground-disturbing activities will 

13 occur (Exelon 2013a). Unit 2 SG replacement, Units 1 and 2 reactor pressure vessel head 

14 replacement, and future urbanization all have the potential to result in impacts on cultural 

15 resources through inadvertent discovery during ground-disturbing activities. However, as 

16 discussed in Section 4.9, Exelon has established draft procedures to ensure cultural resources 

17 are considered in project planning during normal operation of Byron. Therefore, the NRC staff 

18 concludes that the cumulative impact of the proposed license renewal on historic and cultural 

19 resources, when combined with other past, present, and reasonably foreseeable future 

20 activities, would be SMALL.

21 4.16.7 Socioeconomics

22 This section addresses socioeconomic factors that have the potential to be directly or indirectly 

23 affected by changes in operations at Byron in addition to the aggregate effects of other past, 

24 present, and reasonably foreseeable future actions. The primary geographic area of interest 

25 considered in this cumulative analysis is Ogle, Lee, and Winnebago counties, where 

26 approximately 81 percent of Byron employees reside (see Table 3–16). This is where the 

27 economy, tax base, and infrastructure would most likely be affected because Byron workers and 

28 their families reside, spend their incomes, and use their benefits within these counties.

29 As discussed in Section 4.10 of this SEIS, continued operation of Byron during the license 

30 renewal term would have no impact on socioeconomic conditions in the region beyond those 

31 already being experienced. Since Exelon has no plans to hire additional workers during the

32 license renewal term, overall expenditures and employment levels at Byron would remain 

33 relatively constant and unchanged with no additional demand for permanent housing and public 

34 services. In addition, as employment levels and tax payments would not change, there would 

35 be no population or tax revenue-related land-use impacts. Based on this and other information 

36 presented in preceding sections in Chapter 4 of this SEIS, there would be no additional 

37 contributory effect on socioeconomic conditions in the future from the continued operation of 

38 Byron during the license renewal term beyond what is currently being experienced. Therefore, 

39 the only contributory effects would come from reasonably foreseeable future planned activities 

40 at Byron, unrelated to the proposed action (license renewal), and other reasonably foreseeable 

41 planned offsite activities. For example, residential development is forecast for the Byron area, 

42 but not to the point that overall socioeconomic conditions would noticeably change.

43 4.16.7.1 Unit 2 Steam Generator Replacement

44 Exelon indicated that the Unit 2 SG replacement would occur during the license renewal term. 

45 Exelon estimates that SG replacement would occur during a 90-day period paralleling a 
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1 refueling outage or other scheduled maintenance outage. Steam generator replacement would 

2 require 500 personnel, in addition to the 1,400 personnel required for refueling (Exelon 2013a). 

3 These additional workers would create a short-term increase in the demand for temporary 

4 (rental) housing, an increased use of public water and sewer services, and transportation 

5 impacts on access roads in the immediate vicinity of Byron. Given the short amount of time 

6 needed to replace the SG, the additional number of refueling outage and SG replacement 

7 workers and truck deliveries needed to support this one-time replacement, SG replacement 

8 could have a temporary cumulative effect on socioeconomic conditions in the vicinity of the 

9 nuclear plant. However, since the number of nonoutage workers at Byron would not change 

10 after SG replacement, there would be no long-term cumulative socioeconomic impacts in the 

11 region.

12 4.16.7.2 Units 1 and 2 Reactor Pressure Vessel Head Replacement

13 Exelon indicated that the reactor vessel heads would be replaced before the license renewal 

14 term. Exelon estimates that each vessel head replacement would require a one-time increase 

15 of 340 outage workers for 1 week. If the vessel heads were replaced simultaneously, the 

16 number of outage workers would remain at 340, but an additional week of work would be 

17 necessary (Exelon 2013a). These additional workers would create a short-term increase in the 

18 demand for temporary (rental) housing, an increased use of public water and sewer services, 

19 and transportation impacts on access roads in the immediate vicinity of Byron. Given the short 

20 amount of time needed to replace the vessel head and the additional number of workers and 

21 truck deliveries needed to support this one-time replacement of the vessel head, vessel head 

22 replacement could have a temporary cumulative effect on socioeconomic conditions in the 

23 vicinity of the nuclear plant. However, since the number of nonoutage workers at Byron would 

24 not change after reactor vessel head replacement, there would be no long-term cumulative 

25 socioeconomic impacts in the region.

26 4.16.7.3 Conclusion

27 When combined with other past, present, and reasonably foreseeable future activities, there will 

28 be no additional contributory effect on socioeconomic conditions from the continued operation of 

29 Byron during the license renewal period beyond what is currently being experienced. Increases 

30 in the Byron workforce during SG and vessel head replacement would be temporary and have 

31 no long-term socioeconomic impact to the region. Therefore, the NRC staff concludes that the 

32 cumulative socioeconomic impact would be SMALL in the immediate vicinity of Byron.

33 4.16.8 Human Health

34 The NRC and EPA established radiological dose limits for protection of the public and workers 

35 from both acute and long-term exposure to radiation and radioactive materials. These dose 

36 limits are codified in 10 CFR Part 20 and 40 CFR Part 190. As discussed in Section 4.11.1, the 

37 NRC staff concluded impacts to human health from continued plant operations are SMALL. For 

38 the purposes of this analysis, the geographical area considered is the area included within an 

39 80-km (50-mi) radius of the Byron plant site. There are no other nuclear power plants within the 

40 applicable geographical area; however, Byron’s 80-km (50-mi) radius does overlap with the 

41 80-km (50-mi) radii of several nuclear power plants in the area: Quad Cities Nuclear Power 

42 Station, Clinton Power Station, Braidwood Station, LaSalle County Station, and Dresden 

43 Nuclear Power Station. In addition to storing its spent nuclear fuel in a storage pool, Byron also 

44 stores some of its spent nuclear fuel in an onsite independent spent fuel storage installation

45 (ISFSI) (Exelon 2013a).

46 EPA regulations in 40 CFR Part 190 limit the dose to members of the public from all sources in 

47 the nuclear fuel cycle, including nuclear power plants, fuel fabrication facilities, waste disposal 
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1 facilities, and transportation of fuel and waste. As discussed in Section 3.1.4.5, Byron has 

2 conducted a REMP since 1985. This program measures radiation and radioactive materials in 

3 the environment from Byron, its ISFSI, and all other sources. The NRC staff reviewed the 

4 radiological environmental monitoring results for the 5-year period from 2008 to 2012 as part of 

5 the cumulative impacts assessment. The NRC staff’s review of Exelon’s data showed no 

6 indication of an adverse trend in radioactivity levels in the environment from Byron or its ISFSI. 

7 The data showed that there was no measurable impact to the environment from the operations 

8 at Byron.

9 In addition, as discussed in Section 2.1.2 of this SEIS, Exelon stated in its ER that the reactor

10 vessel heads for Units 1 and 2 would be replaced before the license renewal term. In addition, 

11 Exelon may replace the Byron Unit 2 SGs during the license renewal term. The staff expects 

12 the dose to a member of the public and to plant workers from these projects would continue to 

13 be a small fraction of the dose limits and standards specified in 10 CFR Part 20, 10 CFR 

14 Part 50, Appendix I, and 40 CFR Part 190. The NRC and the State of Illinois will regulate any 

15 future development or actions in the vicinity of the Byron site that could contribute to cumulative 

16 radiological impacts.

17 The NRC staff concludes that the cumulative radiological impacts of the proposed license 

18 renewal, when combined with other past, present, and reasonably foreseeable future activities, 

19 would be SMALL. This is based on the NRC staff’s review of REMP data, radioactive effluent 

20 release data, Byron’s expected continued compliance with Federal radiation protection 

21 standards during continued operation and SG replacement, and regulation of any future 

22 development or actions in the vicinity of the Byron site by the NRC and the State of Illinois.

23 4.16.9 Environmental Justice

24 The environmental justice cumulative impact analysis assesses the potential for 

25 disproportionately high and adverse human health and environmental effects on minority and 

26 low-income populations that could result from past, present, and reasonably foreseeable future 

27 actions, including Byron operations during the renewal term. Adverse health effects are 

28 measured in terms of the risk and rate of fatal or nonfatal adverse impacts on human health. 

29 Disproportionately high and adverse human health effects occur when the risk or rate of 

30 exposure to an environmental hazard for a minority or low-income population is significant and 

31 exceeds the risk or exposure rate for the general population or for another appropriate 

32 comparison group. Disproportionately high environmental effects refer to impacts or risks of 

33 impacts on the natural or physical environment in a minority or low-income community that are 

34 significant and appreciably exceed the environmental impact on the larger community. Such 

35 effects may include biological, cultural, economic, or social impacts. Some of these potential 

36 effects have been identified in resource areas presented in preceding sections of this SEIS. 

37 Minority and low-income populations are part of the general public residing in the area and all 

38 would be exposed to the same hazards generated from Byron operations. As previously 

39 discussed in this chapter, the impact from license renewal for all resource areas (e.g., land, air, 

40 water, ecology, and human health) would be SMALL.

41 As discussed in Section 4.12 of this SEIS, there would be no disproportionately high and 

42 adverse impacts on minority and low-income populations from the continued operation of Byron 

43 during the license renewal term. Because Exelon has no plans to hire additional workers during 

44 the license renewal term, employment levels at Byron would remain relatively constant, and 

45 there would be no additional demand for housing or increased traffic. Based on this information 

46 and the analysis of human health and environmental impacts presented in the preceding 

47 sections, it is not likely there would be any disproportionately high and adverse contributory 

48 effect on minority and low-income populations from the continued operation of Byron during the 
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1 license renewal term. Therefore, the only contributory effects would come from the other 

2 reasonably foreseeable future planned activities at Byron, unrelated to the proposed action 

3 (license renewal), and other reasonably foreseeable planned offsite activities.

4 4.16.9.1 Unit 2 Steam Generator Replacement

5 Potential impacts to minority and low-income populations would mostly consist of environmental 

6 and socioeconomic effects (e.g., traffic, employment, and housing impacts). Noise and dust 

7 impacts from power plant modifications would be temporary and limited to onsite activities. 

8 Minority and low-income populations residing along site access roads could experience 

9 increased commuter vehicle traffic during shift changes. Increased demand for inexpensive 

10 rental housing during SG-related power plant modifications could disproportionately affect 

11 low-income populations; however, due to the short duration of the work and the availability of 

12 housing, impacts to minority and low-income populations would be of short duration and limited. 

13 Radiation doses from plant operations after power plant modifications are not expected to 

14 change and will remain within regulatory limits.

15 Based on this information and the analysis of human health and environmental impacts 

16 presented in this section of the SEIS, Unit 2 SG replacement would not have disproportionately 

17 high and adverse human health and environmental effects on minority and low-income 

18 populations residing in the vicinity of Byron.

19 4.16.9.2 Units 1 and 2 Reactor Pressure Vessel Head Replacement

20 Similar to SG replacement, potential impacts to minority and low-income populations from 

21 reactor pressure vessel head replacement would mostly consist of environmental and 

22 socioeconomic effects (e.g., traffic, employment, and housing impacts). Noise and dust impacts 

23 from power plant modifications would be temporary and limited to onsite activities. Minority and 

24 low-income populations residing along site access roads could experience increased commuter 

25 vehicle traffic during shift changes. Increased demand for inexpensive rental housing during 

26 SG-related power plant modifications could disproportionately affect low-income populations; 

27 however, due to the short duration of the work and the availability of housing, impacts to 

28 minority and low-income populations would be of short duration and limited. Radiation doses 

29 from plant operations after power plant modifications are not expected to change and will 

30 remain within regulatory limits.

31 Based on this information and the analysis of human health and environmental impacts 

32 presented in this section of the SEIS, Units 1 and 2 reactor pressure vessel head replacement 

33 would not have disproportionately high and adverse human health and environmental effects on 

34 minority and low-income populations residing in the vicinity of Byron.

35 4.16.9.3 Conclusion

36 The NRC staff concludes that the contributory effects of this action, when combined with other 

37 past, present, and reasonably foreseeable future activities considered, would not cause any 

38 disproportionately high and adverse human health and environmental effects on minority and 

39 low-income populations residing in the vicinity of Byron.

40 4.16.10 Waste Management and Pollution Prevention

41 This section describes waste management impacts during the license renewal term when added 

42 to the aggregate effects of other past, present, and reasonably foreseeable future actions. For 

43 the purpose of this cumulative impacts analysis, the area within a 50-mi (80-km) radius of Byron 

44 was considered. The NRC staff concluded, in Section 4.11, that the potential human health 

45 impacts from Byron’s waste during the license renewal term would be SMALL.
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1 As discussed in Sections 3.1.4 and 3.1.5, Exelon maintains waste management programs for 

2 radioactive and nonradioactive waste generated at Byron and is required to comply with Federal 

3 and State permits and other regulatory requirements for the management of waste material. 

4 Current waste management activities at Byron would likely remain unchanged during the license 

5 renewal term, and continued compliance with Federal and State requirements for radioactive 

6 and nonradioactive waste is expected.

7 Byron is adjacent to the Byron Salvage Yard Superfund Site. This salvage yard was used as a 

8 dumping ground for a variety of nonradioactive waste and debris. As discussed in 

9 Section 3.2.1, all soil and groundwater remedial actions are now completed and groundwater 

10 monitoring plans remain in place (EPA 2008).

11 Based on the above, the NRC staff concludes that the potential cumulative impacts from 

12 radioactive and nonradioactive waste during the license renewal term would be SMALL. 

13 Continued compliance with Federal and State requirements for radioactive and nonradioactive 

14 waste management by Exelon is expected, and the Byron Salvage Yard Superfund Site 

15 remediation actions are complete and noncontributory.

16 4.16.11 Global Climate Change

17 This section addresses the impact of GHG emissions resulting from continued operation of 

18 Byron Station on global climate change when added to the aggregate effects of other past, 

19 present, and reasonably foreseeable future actions. The impacts of climate change on air, 

20 water, and ecological resources are discussed in Section 4.15.3. Climate is influenced by both 

21 natural and human-induced factors; the observed global warming (increase in Earth’s surface 

22 temperature) in the 21st century has been attributed to the increase in GHG emissions resulting 

23 from human activities (Karl et al. 2009). Climate model projections indicate that future climate 

24 change is dependent on current and future GHG emissions (Karl et al. 2009; Pachauri and 

25 Reisinger 2007). As described in Section 4.15.3.1, operations at Byron Station emit GHG 

26 emissions directly and indirectly. Therefore, it is recognized that GHG emissions from 

27 continued Byron Station operation may contribute to climate change.

28 The cumulative impact of a GHG emission source on climate is global. GHG emissions are 

29 transported by wind and become well-mixed in the atmosphere as a result of their long 

30 atmospheric lifetime. Therefore, the extent and nature of climate change is not specific to 

31 where GHGs are emitted. In April 2013, EPA published the official U.S. inventory of GHG 

32 emissions, which identifies and quantifies the primary anthropogenic sources and sinks of 

33 GHGs. The EPA GHG inventory is an essential tool for addressing climate change and 

34 participating with the United Nations Framework Convention on Climate Change to compare the 

35 relative global contribution of different emission sources and GHGs to climate change. In 2011, 

36 the United States emitted 6,702 teragrams (Tg) of carbon dioxide equivalents (CO2e) 

37 (6,702 million metric tons (MMT)), and since 1990 emissions increased at an average annual 

38 rate of 0.4 percent (EPA 2013c). In 2010 and 2011, the total amount of CO2e emissions related 

39 to electricity generation was 2,303 Tg (2,303 MMT) and 2,201 Tg (2,201 MMT), respectively 

40 (EPA 2013c). The EIA reported that, in 2010, electricity production alone in Illinois was 

41 responsible for 94 MMT CO2e (EIA 2013). Facilities that emit 25,000 MT (28,000 t) CO2e or 

42 more per year are required to annually report their GHG emissions to EPA. These facilities are 

43 known as direct emitters and the data is publicly available in EPA’s facility-level information on 

44 GHGs tool (FLIGHT). In 2012, FLIGHT identified four facilities in Ogle County, Illinois, where 

45 the Byron Station is located, that emitted a total of 0.33 MT (0.36 t) CO2e (EPA 2013c). In 2012, 

46 FLIGHT identified 291 facilities in Illinois that emitted a total of 130.3 MMT (130.3 Tg) CO2e

47 (EPA 2013c). 
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1 Appendix E provides a list of present and reasonable foreseeable projects that could contribute 

2 to GHG emissions. Permitting and licensing requirements and other mitigative measures can 

3 minimize the impacts of GHG emissions. For instance, in 2012 EPA issued a final GHG 

4 Tailoring Rule to address GHG emissions from stationary sources under the CAA permitting 

5 requirements; the GHG Tailoring Rule establishes when an emission source will be subject to 

6 permitting requirements and control technology to reduce GHG emissions. On June 25, 2013, 

7 President Obama set forward a plan to reduce carbon pollution. The Climate Action Plan will 

8 reduce carbon pollution, prepare the United States for the impacts of climate change, and lead 

9 international efforts to combat global climate change. Future actions and steps taken to reduce 

10 GHG emissions will lessen the impacts on climate change.

11 EPA’s U.S. inventory of GHG emissions illustrates the diversity of GHG sources emitters, such 

12 as electricity generation, industrial processes, and agriculture. Direct GHG emissions resulting 

13 from operations at Byron Station range from 941 to 1,503 MT (1,040 to 1,657 t) CO2e 

14 (Table 4–23) and total emissions range from 10,872 to 13,962 MT (11,984 to 15,390 t) CO2e. In 

15 comparing Byron Station’s GHG emission contribution to different emissions sources, whether it 

16 be total U.S. GHG emissions, emissions from electricity production in Illinois, or emissions on a 

17 county level, GHG emissions from Byron Station are minor relative to these inventories; this is 

18 evident as presented in Table 4–23. The emissions impact of a single source on climate 

19 change requires that a climate model account for that specific source emission to project the 

20 magnitude and extent of climate change. Climate models indicate that short-term climate 

21 change (through the year 2030) is dependent on past GHG emissions. Therefore, climate 

22 change is projected to occur with or without present and future GHG emissions from Byron 

23 Station. The NRC staff concludes that the impact from the contribution of GHG emissions from 

24 continued operation of Byron Station on climate change would be SMALL. As discussed in 

25 Section 4.15.3.2, climate change and climate-related changes have been observed on a global 

26 level and climate models indicate that future climate change will depend on current and future 

27 GHG emissions. Climate models project that Earth’s average surface temperature will continue 

28 to increase and climate-related changes will persist. Therefore, the cumulative impact of GHG 

29 emissions on climate change is noticeable but not destabilizing. The NRC staff concludes that 

30 the cumulative impacts from the proposed license renewal and other past, present, and 

31 reasonably foreseeable projects would be MODERATE.

32 Table 4–23. Comparison of GHG Emission Inventories

Source CO2e MMT/year

Global Fossil Fuel Combustion Emissions (2011)(1) 31,800

U.S. Emissions (2011)(2) 6,702

Illinois (2012)(3) 130.3

Ogle County, Illinois (2012)(3) 0.33

Byron Station Emissions (2008–2012)(4) 0.010–0.013

(1) Source: IEA 2012

(2)

 Source: EPA 2013b

(3) GHG emissions account only for direct emitters, those facilities that emit 25,000 MT or more a year (EPA 2013c).

(4)

Emissions include direct and indirect emissions from operation of Byron (Exelon 2013b).

Sources: EPA 2013b, 2013c; Exelon 2013b; IEA 2012
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1 4.16.12 Summary of Cumulative Impacts

2 The NRC staff considered the potential impacts resulting from the operation of Byron during the 

3 period of extended operation and other past, present, and reasonably foreseeable future actions 

4 near Byron. The preliminary determination is that the potential cumulative impacts would range 

5 from SMALL to MODERATE, depending on the resource. Table 4–24 summarizes the 

6 cumulative impacts on resources areas.
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1 Table 4–24. Summary of Cumulative Impacts on Resource Areas

Resource Area Cumulative Impact

Air Quality and 

Noise

Past, present, and reasonably foreseeable future activities exist in the geographic 

areas of interest (local for noise; local and regional for criteria pollutants) that could 

affect air quality and noise resources. However, the incremental contribution of 

impacts on air quality and noise resources from plant operations at Byron Station 

would be minimal. The NRC staff concludes that cumulative impacts from other past, 

present, and reasonably foreseeable future actions on air quality and noise resources 

in the geographic areas of interest would be SMALL.

Geology and 

Soils

Any use of geologic materials, such as aggregates to support operation and 

maintenance activities, would be procured from local and regional sources. These 

materials are abundant in the region, and geologic conditions are not expected to 

change during the license renewal term. Thus, activities associated with continued 

operations are not expected to affect the geologic environment. Considering ongoing 

activities and reasonably foreseeable actions, the NRC staff concludes that the 

cumulative impacts on geology and soils during the Byron license renewal term would 

be SMALL.

Water 

Resources

Considering ongoing activities and reasonably foreseeable actions, the NRC staff 

concludes that cumulative impact of the proposed license renewal, combined with 

other past, present, and reasonably foreseeable future activities, would be SMALL on 

surface water and groundwater use and quality. The Byron facility has not impacted 

and is not reasonably expected to impact the quality of groundwater in any aquifers

that are a current or potential future source of water for offsite users, and groundwater 

supply is abundant enough to meet reasonably foreseeable demand. Consumptive 

surface water use from continued Byron operations will continue to be a very small 

percentage of the overall flow of the Rock River, and ongoing and future surface 

water demands by users are expected to be supported. Surface water discharges to 

the Rock River by Byron and other industrial users will be monitored and kept at 

acceptable limits via NPDES permits.

Terrestrial 

Ecology

Section 4.6 of this SEIS concludes that the impact from the proposed license renewal 

would not noticeably alter the terrestrial environment and would be SMALL. However, 

as environmental stressors such as agricultural runoff and residential development 

continue over the proposed license renewal term, certain attributes of the terrestrial 

environment (such as species diversity and distribution) are likely to noticeably 

change. The NRC staff does not expect these impacts to destabilize any important 

attributes of the terrestrial environment, but instead cause gradual change, which 

would allow the terrestrial environment to adapt appropriately. The NRC staff 

concludes that the cumulative impacts of the proposed license renewal of Byron, and 

other past, present, and reasonably foreseeable future projects or actions, would 

result in MODERATE impacts to terrestrial resources.

Aquatic Ecology

NRC staff concludes that the cumulative impacts on aquatic resources in the Rock 

River are MODERATE based on past, present, and reasonably foreseeable future 

actions. This level of impact is primarily the result of past river channelization and 

damming and ongoing runoff and sedimentation from agriculture. The environmental 

effects of these actions are clearly noticeable, but available information on the status 

of the Rock River aquatic communities does not indicate that these effects have 

destabilized any important attribute of the community in the vicinity of Byron. The 

incremental, site-specific impact from the continued operation of Byron during the 

license renewal period would be minor and not noticeable in comparison to

cumulative impact on the aquatic ecology.
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Resource Area Cumulative Impact

Historical and 

Cultural 

Resources 

As described in Section 4.9, no cultural resources would be adversely affected by 

Byron license renewal activities as no associated changes or ground-disturbing 

activities will occur. Exelon has established draft procedures to ensure cultural 

resources are considered in project planning during normal operation of Byron. 

Therefore, the NRC staff concludes that the cumulative impact of the proposed 

license renewal when combined with other past, present, and reasonable foreseeable 

future activities on historic and cultural resources would be SMALL.

Socioeconomics

When combined with other past, present, and reasonably foreseeable future activities, 

there will be no additional contributory effect on socioeconomic conditions from the 

continued operation of Byron during the license renewal period beyond what is 

currently being experienced. Increases in the Byron workforce during SG and vessel 

head replacement would be temporary and have no long-term socioeconomic impact 

to the region. Therefore, the NRC staff concludes that the cumulative socioeconomic 

impact would be SMALL in the immediate vicinity of Byron.

Human Health

The NRC staff concludes that the cumulative radiological impacts of the proposed 

license renewal, when combined with other past, present, and reasonably foreseeable 

future activities, would be SMALL.

Environmental 

Justice

The NRC staff concludes that the contributory effects of this action, when combined 

with other past, present, and reasonably foreseeable future activities considered, 

would not cause any disproportionately high and adverse human health and 

environmental effects on minority and low-income populations residing in the vicinity 

of Byron.

Waste 

Management 

NRC staff concludes that the potential cumulative impacts from radioactive and 

nonradioactive waste during the license renewal term would be SMALL. Continued 

compliance with Federal and State requirements for radioactive and nonradioactive 

waste management by Exelon is expected, and the Byron Salvage Yard Superfund 

Site remediation actions are complete and noncontributory.

Global Climate 

Change

As discussed in Section 4.15.3.2, climate change and climate-related changes have 

been observed on a global level, and climate models indicate that future climate 

change will depend on present and future GHG emissions. Climate models project 

that Earth’s average surface temperature will continue to increase and climate-related 

changes will persist. Therefore, the cumulative impact of GHG emissions on climate 

change is noticeable but not destabilizing. The NRC staff concludes that the 

cumulative impacts from the proposed license renewal and other past, present, and 

reasonably foreseeable projects would be MODERATE.

1 4.17 Resource Commitments Associated With the Proposed Action

2 4.17.1 Unavoidable Adverse Environmental Impacts

3 Unavoidable adverse environmental impacts are impacts that would occur after implementation 

4 of all workable mitigation measures. Carrying out any of the energy alternatives considered in 

5 this SEIS, including the proposed action, would result in some unavoidable adverse 

6 environmental impacts.

7 Minor unavoidable adverse impacts on air quality would occur due to emission and release of 

8 various chemical and radiological constituents from power plant operations. Nonradiological 

9 emissions resulting from power plant operations are expected to comply with EPA emissions 

10 standards, although the alternative of operating a fossil-fueled power plant in some areas may 
Environmental Consequences and Mitigating Actions

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1 worsen existing attainment issues. Chemical and radiological emissions would not exceed the 

2 National Emission Standards for Hazardous Air Pollutants.

3 During nuclear power plant operations, workers and members of the public would face 

4 unavoidable exposure to radiation and hazardous and toxic chemicals. Workers would be 

5 exposed to radiation and chemicals associated with routine plant operations and the handling of 

6 nuclear fuel and waste material. Workers would have higher levels of exposure than members 

7 of the public, but doses would be administratively controlled and would not exceed standards or 

8 administrative control limits. In comparison, the alternatives involving the construction and 

9 operation of a nonnuclear power generating facility would also result in unavoidable exposure to 

10 hazardous and toxic chemicals to workers and the public.

11 The generation of spent nuclear fuel and waste material, including low-level radioactive waste, 

12 hazardous waste, and nonhazardous waste, would also be unavoidable. In comparison, 

13 hazardous and nonhazardous wastes would also be generated at nonnuclear power generating 

14 facilities. Wastes generated during plant operations would be collected, stored, and shipped for 

15 suitable treatment, recycling, or disposal in accordance with applicable Federal and State 

16 regulations. Because of the costs of handling these materials, power plant operators would be 

17 expected to carry out all activities and optimize all operations in a way that generates the 

18 smallest amount of waste possible.

19 4.17.2 Relationship Between Short-Term Use of the Environment and Long-Term 

20 Productivity

21 The operation of power generating facilities would result in short-term uses of the environment, 

22 as described in this chapter. “Short term” is the period of time that continued power generating 

23 activities take place.

24 Power plant operations require short-term use of the environment and commitment of 

25 resources, as well as commitment of certain resources (e.g., land and energy) indefinitely or 

26 permanently. Certain short-term resource commitments are substantially greater under most 

27 energy alternatives, including license renewal, than under the no-action alternative because of 

28 the continued generation of electrical power and the continued use of generating sites and 

29 associated infrastructure. During operations, all energy alternatives require similar relationships 

30 between local short-term uses of the environment and the maintenance and enhancement of 

31 long-term productivity.

32 Air emissions from power plant operations introduce small amounts of radiological and 

33 nonradiological constituents to the region around the plant site. Over time, these emissions 

34 would result in increased concentrations and exposure, but they are not expected to impact air 

35 quality or radiation exposure to the extent that public health and long-term productivity of the 

36 environment would be impaired.

37 Continued employment, expenditures, and tax revenues generated during power plant 

38 operations directly benefit local, regional, and State economies over the short term. Local 

39 governments investing project-generated tax revenues into infrastructure and other required 

40 services could enhance economic productivity over the long term.

41 The management and disposal of spent nuclear fuel, low-level radioactive waste, hazardous 

42 waste, and nonhazardous waste require an increase in energy and consume space at 

43 treatment, storage, or disposal facilities. Regardless of the location, the use of land to meet 

44 waste disposal needs would reduce the long-term productivity of the land.
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1 Power plant facilities are committed to electricity production over the short term. After 

2 decommissioning these facilities and restoring the area, the land could be available for other 

3 future productive uses.

4 4.17.3 Irreversible and Irretrievable Commitment of Resources

5 This section describes the irreversible and irretrievable commitment of resources that have 

6 been noted in this SEIS. Resources are irreversible when primary or secondary impacts limit 

7 the future options for a resource. An irretrievable commitment refers to the use or consumption 

8 of resources that are neither renewable nor recoverable for future use. Irreversible and 

9 irretrievable commitment of resources for electrical power generation include the commitment of 

10 land, water, energy, raw materials, and other natural and manmade resources required for 

11 power plant operations. In general, the commitment of capital, energy, labor, and material 

12 resources are also irreversible.

13 The implementation of any of the energy alternatives considered in this SEIS would entail the 

14 irreversible and irretrievable commitment of energy, water, chemicals, and in some cases, fossil 

15 fuels. These resources would be committed during the license renewal term and over the entire 

16 life cycle of the power plant, and they would be unrecoverable.

17 Energy expended would be in the form of fuel for equipment, vehicles, and power plant 

18 operations and electricity for equipment and facility operations. Electricity and fuel would be 

19 purchased from offsite commercial sources. Water would be obtained from existing water 

20 supply systems. These resources are readily available, and the amounts required are not 

21 expected to deplete available supplies or exceed available system capacities.

22 4.18 References

23 10 CFR Part 20. Code of Federal Regulations, Title 10, Energy, Part 20, “Standards for 

24 protection against radiation.”

25 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic licensing of 

26 production and utilization facilities.”

27 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

28 protection regulations for domestic licensing and related regulatory functions.”

29 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

30 renewal of operating licenses for nuclear power plants.”

31 10 CFR Part 100. Code of Federal Regulations, Title 10, Energy, Part 100, “Reactor site 

32 criteria.”

33 36 CFR Part 60. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property, 

34 Part 60, “National register of historic places.”

35 36 CFR Part 800. Code of Federal Regulations. Title 36, Parks, Forests, and Public Property, 

36 Part 800, “Protection of historic properties.”

37 40 CFR Part 51. Code of Federal Regulations, Title 40, Protection of Environment, Part 51, 

38 “Requirements for preparation, adoption, and submittal of implementation plans.”

39 40 CFR Part 60. Code of Federal Regulations, Title 40, Protection of Environment, Part 60, 

40 "Standards of performance for new stationary sources.”

41 40 CFR Part 63. Code of Federal Regulations, Title 40, Protection of Environment, Part 63, 

42 “National emission standards for hazardous air pollutants for source categories.”
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1 40 CFR Part 75. Code of Federal Regulations, Title 40, Protection of Environment, Part 75, 

2 “Continuous emission monitoring.”

3 40 CFR Part 81. Code of Federal Regulations, Title 40, Protection of Environment, Part 81,

4 “Designation of areas for air quality planning purposes.”

5 40 CFR Part 93. Code of Federal Regulations, Title 40, Protection of Environment, Part 93, 

6 “Determining conformity of Federal actions to state or Federal implementation plans.”

7 40 CFR Part 190. Code of Federal Regulations, Title 40, Protection of Environment, Part 190, 

8 “Environmental radiation protection standards for nuclear power operations.”

9 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 

10 “Interagency cooperation—Endangered Species Act of 1973, as amended.”

11 49 FR 34658. U.S. Nuclear Regulatory Commission. “Waste confidence decision and 

12 requirements for licensee actions regarding the disposition of spent fuel upon expiration of 

13 reactor operating licenses; Final Rules.” Federal Register 49 (171):34658:34696. 

14 August 31, 1984.

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21 61 FR 28467. U.S. Nuclear Regulatory Commission. “Environmental review for renewal of 

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35 75 FR 81032. U.S. Nuclear Regulatory Commission. “Consideration of environmental impacts of 

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38 75 FR 81037. U.S. Nuclear Regulatory Commission. “Waste confidence decision update.” 

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5-1 

1 5.0 CONCLUSION

2 This draft supplemental environmental impact statement (SEIS) contains the environmental 

3 review of the application for renewed operating licenses for Byron Station, Units 1 and 2 

4 (Byron), submitted by Exelon Generation Company, LLC (Exelon), as required by the Code of 

5 Federal Regulations (CFR), Part 51 of Title 10 (10 CFR Part 51), the U.S. Nuclear Regulatory 

6 Commission’s (NRC’s) regulations that implement the National Environmental Policy Act

7 (NEPA). This chapter presents conclusions and recommendations from the site-specific 

8 environmental review of Byron. Section 5.1 summarizes the environmental impacts of license 

9 renewal; Section 5.2 presents a comparison of the environmental impacts of license renewal 

10 and energy alternatives; and Section 5.3 presents the NRC staff conclusions and 

11 recommendation.

12 5.1 Environmental Impacts of License Renewal

13 The NRC staff’s review of site-specific environmental issues in this SEIS leads to the conclusion 

14 that issuing renewed licenses at Byron would have SMALL impacts for the Category 2 issues 

15 applicable to license renewal at Byron. The NRC staff considered mitigation measures for each 

16 Category 2 issue, as applicable. The NRC staff concluded that no additional mitigation measure 

17 is warranted. 

18 5.2 Comparison of Alternatives

19 In Chapter 4, the staff considered the following alternatives to Byron license renewal:

20  no-action alternative

21  new nuclear alternative

22  integrated gasification combined cycle (IGCC) alternative

23  natural gas combined cycle (NGCC) alternative

24  combination alternative (NGCC, wind, solar)

25  purchased power

26 Based on the summary of environmental impacts provided in Table 2-2, the NRC staff 

27 concluded that the environmental impacts of renewal of the operating licenses for Byron would 

28 be smaller than those of feasible and commercially viable alternatives. The no-action 

29 alternative, the act of shutting down Byron on or before its licenses expires, would have SMALL 

30 environmental impacts in most areas with the exception of socioeconomic impacts, which would 

31 have SMALL to LARGE environmental impacts. Continued operations would have SMALL 

32 environmental impacts in all areas. The staff concluded that continued operation of the existing 

33 Byron units is the environmentally preferred alternative.
Conclusion

5-2 

1 5.3 Recommendations

2 The NRC staff’s preliminary recommendation is that the adverse environmental impacts of 

3 license renewal for Byron are not so great that preserving the option of license renewal for 

4 energy-planning decisionmakers would be unreasonable. This recommendation is based on the 

5 following:

6  the analysis and findings in NUREG-1437, Volumes 1 and 2, Generic 

7 Environmental Impact Statement for License Renewal of Nuclear Plants; 

8  the environmental report submitted by Exelon;

9  consultation with Federal, state, and local agencies;

10  the NRC staff’s environmental review; and

11  consideration of public comments received during the scoping process.
6-1 

1 6.0 LIST OF PREPARERS

2 Members of the U.S. Nuclear Regulatory Commission’s (NRC’s) Office of Nuclear Reactor 

3 Regulation (NRR) prepared this supplemental environmental impact statement with assistance 

4 from other NRC organizations and support from Argonne National Laboratory (ANL), Pacific 

5 Northwest National Laboratory (PNNL), and BLH Technologies, Inc. (BLH). ANL and PNNL 

6 provided support as identified in Table 6–1. BLH provided support for technical editing reviews. 

7 Table 6–1 identifies each contributor’s name, affiliation, and function or expertise.
List of Preparers

6-2 

1 Table 6–1. List of Preparers

2 (in alphabetical order)

Name Affiliation Function or Expertise

NRC

Russell Chazell NRR Alternatives

Kevin Folk NRR Water Resources: Surface Water

William Ford NRR Geology; Water Resources: Groundwater

Briana Grange NRR

Aquatic Resources; Special Status Species and Habitats; 

Microbiological Hazards; Land Use and Visual Resources; 

Terrestrial Resources

Robert Hoffman NRR Meteorology, Air Quality, and Noise

Lois James NRR Environmental Project Manager

Steven Klementowicz NRR Human Health; Waste Management and Pollution Prevention

Emily Larson NRR Historic and Cultural Resources; Environmental Justice

Dennis Logan NRR Land Use and Visual Resources; Terrestrial Resources; Aquatic 

Resources

Nancy Martinez NRR Air Quality Climatic Change Meteorology, Air Quality, and Noise; 

Greenhouse Gas Emissions and Climate Change

John Parillo NRR SAMA

Jeffrey Rikhoff NRR Socioeconomics; Historic and Cultural Resources

Allison Travers NRR Land Use and Visual Resources; Terrestrial Resources

Brian Wittick NRR Branch Chief

David Wrona NRR Branch Chief

Contractor(a)

Young Soo Chang ANL Air Quality and Climate

Terri Patton ANL Water Resources: Surface Water; Groundwater

Konnie Wesott ANL Alternatives

Ellen White ANL Alternatives

SAMA Contractor(b)

Bob Schmidt PNNL SAMA

Bruce Schmitt PNNL SAMA

Steve Short PNNL SAMA

(a) ANL is managed by UChicago Argonne, LLC, for the U.S. Department of Energy. (b) PNNL is operated by Battelle for the U.S. Department of Energy. 
7-1 

1 7.0 LIST OF AGENCIES, ORGANIZATIONS, AND PERSONS 

2 TO WHOM COPIES OF THIS SEIS ARE SENT

3 Table 7–1. List of Agencies, Organizations, and Persons to Whom Copies 

4 of This SEIS Are Sent

Name and Title Company and Address

Brent Baker, President

Byron Chamber of Commerce

232 W. 2nd Street

PO Box 405

Byron, IL 61010

John “Rocky” Barrett, Chairman

Citizen Potawatomi Nation

1601 S. Gordon Cooper Dr.

Shawnee, OK 74801

Jenny Beckman, Campaign Manager/Ogle County 

Director, United Way of Rock River Valley

United Way of Rock River Valley

612 N. Main Street Suite 300

Rockford, IL 61103-6998

815-968-5400

Galen Bennett, Chief Byron Fire Protection District

E-mail

John Blackhawk, Chairman

Winnebago Tribe of Nebraska

100 Bluff Street

PO Box 687

Winnebago, NE 68071

Ronald Bolin, Exelon Employee Resident

Johnathan L. Buffalo, Historic Preservation Director

Sac and Fox Tribe of the Mississippi in 

Iowa/Meskwaki

349 Meskwaki Road

Tama, IA 52339

Scott H. Christiansen, Chairman Winnebago County Board of Commissioners

E-mail

Allen Christianson, Exelon Employee

Exelon Generation Company, LLC

8457 Wendy Court

Byron, IL 61010

Ron Colson, Member Blackhawk Hills Regional Council

E-mail

Tom Demmer, Illinois State Representative

District Office

1221 Currency Court

Suite B

Rochelle, IL 61068

Michael Dougherty, Chairperson

Sac and Fox Nation of Missouri in Kansas and 

Nebraska

305 N. Main Street

Reserve, KS 66434

Bruce Drawbridge, Vice President

CBI Chicago Bridge and Iron

444 N. Wells St, Suite 602

Chicago, IL 60654-8198
List of Agencies, Organizations, and Persons to Whom Copies of This SEIS Are Sent

7-2 

Name and Title Company and Address

Mr. Jon Duyvejonck, Fish and Wildlife Biologist

Rock Island Field Office

U.S. Fish and Wildlife Service

1511 47th Avenue

Moline, IL 61265

EIS Filing Section

U.S. Environmental Protection Agency (EPA)

1200 Pennsylvania Avenue, NW

Washington, DC 20004

Environmental Law and Policy Center (ELPC)

Environmental Law and Policy Center

35 E. Wacker Drive, Suite 1600

Chicago, IL 60601

Sarah Faller, Exelon Employee Exelon Generation Company, LLC

E-mail

Harold “Gus” Frank, Chairman

Forest County Potawatomi

5416 Everybody’s Rd.

Crandon, WI 54520

John P. Froman, Chief

Peoria Tribe of Indians of Oklahoma

118 S. Eight Tribes Trail

P.O. Box 1527

Miami, OK 74355

Jarid Funderburg, Representative of Congressman 

Kinzinger

Congressman Kinzinger’s Office

401 Whitney Blvd.

Belvidere, IL 61008

Michael P. Gallagher, Vice President, License 

Renewal Projects

Exelon Generation Company, LLC

200 Exelon Way

Kennett Square, PA 19348

Ron Gibson, Member Byron Township

E-mail

Kim P. Gouker, Member

Ogle County Board

P.O. Box 926

Byron, IL 61010

Jon Greendeer, President

Ho-Chunk Nation

W9814 Airport Road

P.O. Box 667

Black River Falls, WI 54615-0667

Anne E. Haaker, Deputy State Historic 

Preservation Officer

Preservation Services Division

Illinois Historic Preservation Agency

1 Old State Capitol Plaza

Springfield, IL 62701-1507

Dr. James Hammack, Superintendent Byron, Illinois School District

E-mail

Michael Harn, Sheriff Sheriff Ogle County

E-mail

Candace Humphrey, Emergency Management 

Director

Ogle County, Illinois

E-mail
List of Agencies, Organizations, and Persons to Whom Copies of This SEIS Are Sent

7-3 

Name and Title Company and Address

Russ Kearney, Site Vice President

Exelon Generation Company, LLC

4448 N. German Church

Byron, IL 61010-9750

Joe Klinger, Assistant Director Illinois Emergency Management Agency

E-mail

David Kraft, Respresentative

National Energy Information Service (NEIS)

4311 West Diversey Ave. #16

Chicago, IL 60647

Douglas G. Lankford, Chief

Miami Tribe of Oklahoma

P.O. Box 1326

Miami, OK 74355

Dennis Lolli, Emergency Management Director Winnebago County, Illinois

E-mail

Sandra Kaye Massey, Member

Sac and Fox Nation

Administration Building

920883 S. Hwy 99 Bldg A

Stroud, OK 74079

Jim McGhee, Senior Resident Inspector 4448 N. German Church

Byron, IL 61010-9750

Charles Medrano, Exelon Employee Exelon Generation Company, LLC

E-mail

Tom Melius, Midwest Regional Director

Midwest Regional Director

U.S. Fish and Wildlife Service

5600 American Blvd. West, Suite 990

Bloomington, MN 55437-1458

Kenneth Meshigaud, Tribal Chairperson

Hannahville Indian Community, Band of 

Potawatomi

N14911 Hannahville B-1 Rd.

Wilson, MI 49896

Chris Millard Resident

Kelli Mosteller, THPO 1601 S. Gordon Cooper Dr.

Shawnee, OK 74801

Todd R. Murray, Chief Byron Police Department, Byron, Illinois

E-mail

Reid Nelson, Director

Office of Federal Agency Programs

Advisory Council on Historic Preservation

Old Post Office Building

1100 Pennsylvania Avenue, NW Suite 803

Washington, DC 20004

Richard C. Nelson, Field Office Supervisor

Rock Island Field Office

U.S. Fish and Wildlife Service

1511 47th Avenue

Moline, Illinois 61265

Doreen O’Brien, Public Health Administrator Ogle County Health Department

E-mail
List of Agencies, Organizations, and Persons to Whom Copies of This SEIS Are Sent

7-4 

Name and Title Company and Address

Doug O’Brien, Member Illinois Clean Energy Coalition

E-mail

Penny O’Rourke

Byron Public Library District

100 S. Washington St.

Byron, IL 61010

Steve Ortiz, Chair

Prairie Band of Potawatomi Nation

16281 Q Road

Mayetta, KS 66509

Cindy Pederson, Regional Administrator

U.S. Nuclear Regulatory Commission

Region III

2443 Warrenville Road

Lisle, IL 60532

Elizabeth Poole, Environmental Scientist

NEPA Implementation Section

U.S. Environmental Protection Agency

77 W Jackson Blvd. E-19J

Chicago, IL 60604

John Quackenbush, THPO

HCN Cultural Resources

W9036 Hwy 54 East

Black River Falls, WI 54615

Nancy L. Ranek, Environmental Lead for Byron 

License Renewal 

Exelon Generation Company, LLC

200 Exelon Way, KSA-2-E 

Kennett Square, PA 19348

Alvin Sanache, Chairman

Sac and Fox Tribe of the Mississippi in 

Iowa/Meskwaki

349 Meskwaki Road

Tama, IA 52339

Tony Sullins, Threatened and Endangered Species 

Chief

U.S. Fish and Wildlife Service

Midwest Region (Region 3)

5600 American Blvd. West, Suite 990

Bloomington, Minnesota 55437-1458

Ed Stirling, Resident E-mail

George Strack, THPO P.O. Box 1326

Miami, OK 74355

Brittany Theis, Attorney

WHITT LAW LLC

70 South Constitution Drive

Aurora, IL 60506-7335

Ruth Thomas, Resident Resident

Patti Thompson, Public Information Officer Illinois Emergency Management Agency

E-mail

George Thurman, Principal Chief

Sac and Fox Nation

Administration Building

920883 S. Hwy 99 Bldg A

Stroud, OK 74079

Todd Tucker, Executive Director Byron Forest Preserve

E-mail
List of Agencies, Organizations, and Persons to Whom Copies of This SEIS Are Sent

7-5 

Name and Title Company and Address

Matt Wesaw, Chairman

Pokagon Band of Potawatomi

58620 Sink Road

Box 180

Dowagiac, MI 49047

Dan Westin, Rochelle Utilities Employee

Rochelle Utilities

333 Lincoln Highway

Rochelle, IL 61068

Kenneth Westlake, EPA Employee

EPA Region 5 - Main Office

77 W. Jackson Boulevard

Chicago, IL 60604

312-353-2000

Tom Wolf, Member

Illinois Chamber of Commerce

300 S. Wacker #1600

Chicago, IL 60606

Mike Zimmerman, Jr., THPO

Department of Natural Resources

P.O. Box 180

58620 Sink Rd.

Dowagiac, MI 49047

8-1 

1 8.0 INDEX

2 3 A

4 accidents.........xxxiv, 4-62, 4-63, 4-65, A-6, F-1, 

5 F-3, F-4, F-6, F-7, F-9, F-10, F-15, F-16, F-17, 

6 F-21, F-34, F-37, F-39, F-40, F-41, F-44, F-47

7 Advisory Council on Historic Preservation 

8 (ACHP)...............xxix, 1-6, 4-46, 4-126, 7-3, B-7, 

9 C-3, C-4 

10 aesthetic........................... 3-29, 3-91, 4-49, 4-75

11 alternatives ......... v, xxvi, 1-5, 2-1, 2-3, 2-4, 2-5, 

12 2-6, 2-8, 2-18, 2-21, 2-23, 2-25, 2-28, 4-1, 4-5, 

13 4-16, 4-17, 4-18, 4-19, 4-20, 4-21, 4-22, 4-27, 

14 4-28, 4-29, 4-30, 4-34, 4-35, 4-36, 4-41, 4-45, 

15 4-50, 4-57, 4-58, 4-63, 4-64, 4-70, 4-71, 4-75, 

16 4-84, 4-85, 4-87, 4-91, 4-92, 4-115, 4-116, 

17 4-117, 5-1, A-1, A-7, B-3, C-2, F-26, F-27

18 archaeological resources........... 1-6, 2-5, 3-65, 

19 3-67, 4-47, 4-48, 4-49, 4-106

20 B

21 biocide......................................................... 4-60

22 biological assessment......................... C-1, C-2 

23 biota................................ 4-34, 4-38, 4-96, 4-105

24 burnup........................................................... 3-5 

25 C

26 chronic effects................................... 4-58, 4-59

27 Clean Air Act (CAA) ...... xxx, 3-20, 3-102, 4-10, 

28 4-11, 4-14, 4-99, 4-112, 4-119, 4-121, B-4, B-9 

29 closed-cycle cooling xxv, 2-9, 2-14, 2-15, 2-16, 

30 3-5, 4-25

31 Coastal Zone Management Act (CZMA)..... B-5 

32 consumptive use............ 3-28, 4-24, 4-25, 4-26, 

33 4-27, 4-28, 4-29, 4-30

34 cooling system .... xxiv, xxv, xxxi, 1-4, 1-6, 2-11, 

35 2-14, 2-15, 2-16, 3-5, 3-28, 3-29, 3-47, 3-60, 

36 3-87, 4-18, 4-23, 4-25, 4-39, 4-40, 4-59, F-9, 

37 F-23, F-32

38 core damage frequency (CDF)....... xx, xxi, xxx, 

39 4-65, F-1, F-2, F-3, F-5, F-6, F-7, F-8, F-9, F-10, 

40 F-11, F-12, F-13, F-14, F-21, F-22, F-24, F-25, 

41 F-26, F-27, F-28, F-29, F-34, F-35, F-37, F-38, 

42 F-40, F-41

43 Council on Environmental Quality 

44 (CEQ) ............xxx, 1-3, 3-90, 3-91, 3-100, 4-104, 

45 4-105, 4-119

46 critical habitat........ 3-60, 3-61, 3-62, 3-63, 3-64, 

47 3-96, 4-41, 4-42, 4-43, 4-44, 4-81, B-7, C-1, C-2 

48 cultural resources.....xxv, 2-5, 2-27, 3-17, 3-65, 

49 3-67, 4-45, 4-47, 4-48, 4-49, 4-50, 4-79, 4-80, 

50 4-81, 4-86, 4-96, 4-106, 4-107, 4-115, B-1, B-7 

51 D

52 design-basis accident ..........................xxxi, 4-1 

53 discharges ....... xxv, 2-9, 2-11, 2-14, 2-15, 2-16, 

54 3-1, 3-5, 3-8, 3-9, 3-10, 3-15, 3-17, 3-18, 3-22, 

55 3-27, 3-28, 3-29, 3-30, 3-36, 3-37, 3-38, 3-47, 

56 3-48, 3-52, 3-53, 3-57, 3-59, 3-87, 4-23, 4-25, 

57 4-26, 4-27, 4-28, 4-37, 4-39, 4-58, 4-59, 4-60, 

58 4-88, 4-100, 4-105, 4-106, A-4, A-8, B-4, B-5, 

59 E-3, F-32, F-36

60 dose......xxxvii, 3-9, 3-10, 3-11, 3-12, 3-86, 3-95, 

61 4-65, 4-76, 4-86, 4-108, 4-109, 4-127, B-3, B-6, 

62 F-4, F-16, F-17, F-18, F-19, F-20, F-22, F-27, 

63 F-28, F-32, F-34, F-37, F-38, F-41

64 dredging....... 2-11, 3-32, 3-51, 3-60, 4-23, 4-26, 

65 4-27, 4-28, 4-34, 4-37, 4-39

66 E

67 education........................................... 3-78, 4-51

68 electromagnetic fields.... xxxi, 3-89, 4-58, 4-59, 

69 4-68, 4-69

70 endangered and threatened species .........xxv, 

71 1-6, 3-40, 3-55, 3-97, B-1, B-7, C-1 

72 Endangered Species Act (ESA).........xxvi, xxxi, 

73 1-6, 1-7, 1-8, 2-5, 3-40, 3-44, 3-59, 3-96, 3-102, 

74 4-41, 4-42, 4-43, 4-44, 4-45, 4-81, 4-95, 4-96, 

75 4-118, 4-122, 4-123, B-7, B-9, C-1, C-2, C-6, 

76 D-1 

77 entrainment ..................... 3-60, 4-37, 4-38, 4-39

78 environmental justice (EJ)....... 2-5, 3-91, 3-96, 

79 4-71, 4-72, 4-81, 4-87, 4-109, 4-118

80 essential fish habitat (EFH)..... xxxi, 3-65, 4-41, 

81 4-43, 4-44, 4-81, B-7, C-3 

82 eutrophication.......................... 3-60, 4-37, 4-96

83 evaporative loss............................................ 3-8 

84 F

85 Fish and Wildlife Coordination Act 

86 (FWCA)................................................. xxxii, B-9 
Index

8-2 

1 G

2 Generic Environmental Impact Statement 

3 (GEIS) .......v, xxiii, xxiv, xxvii, xxxii, 1-3, 1-4, 1-5, 

4 1-6, 1-7, 1-8, 2-1, 2-2, 2-3, 2-4, 2-19, 2-21, 2-32, 

5 2-33, 3-72, 3-89, 3-109, 4-1, 4-2, 4-5, 4-6, 4-11, 

6 4-14, 4-17, 4-21, 4-22, 4-23, 4-24, 4-25, 4-27, 

7 4-28, 4-29, 4-30, 4-31, 4-32, 4-33, 4-34, 4-35, 

8 4-37, 4-38, 4-39, 4-40, 4-41, 4-46, 4-50, 4-51, 

9 4-58, 4-59, 4-61, 4-62, 4-63, 4-71, 4-76, 4-77, 

10 4-78, 4-79, 4-83, 4-84, 4-85, 4-86, 4-87, 4-88, 

11 4-90, 4-91, 4-126, 4-127, 5-2, A-1, A-6, A-10, 

12 D-3, F-47

13 greenhouse gases............xxxii, 2-7, 2-14, 2-28, 

14 3-21, 3-96, 4-7, 4-119

15 groundwater .... xxv, 3-5, 3-15, 3-17, 3-29, 3-32, 

16 3-34, 3-36, 3-37, 3-79, 3-87, 4-22, 4-24, 4-25, 

17 4-26, 4-27, 4-28, 4-29, 4-30, 4-72, 4-73, 4-86, 

18 4-95, 4-100, 4-101, 4-102, 4-111, 4-114, B-1, 

19 E-3 

20 H

21 hazardous waste .......... 3-14, 3-87, 3-95, 4-116, 

22 B-6, B-9 

23 high-level waste ...... xxiv, 1-4, 4-76, 4-77, 4-78, 

24 4-82, 4-83, 4-86

25 I

26 Illinois Department of Commerce and 

27 Economic Opportunity (DCEO)........... xix, xxxi, 

28 3-72, 3-73, 3-101, F-45

29 Illinois Department of Natural Resources 

30 (IDNR) ... xxxiii, 3-8, 3-16, 3-17, 3-32, 3-38, 3-42, 

31 3-44, 3-46, 3-47, 3-60, 3-63, 3-64, 3-105, 3-107, 

32 3-111, 4-38, 4-101, 4-106, 4-123, 4-124, 4-127, 

33 E-4, E-5, E-6 

34 Illinois Department of Public Health 

35 (IDPH) .........xxxiii, 3-36, 3-88, 3-106, 4-59, 4-61, 

36 4-122, 4-123

37 Illinois Department of Transportation 

38 (IDOT) .............xxxiii, 3-8, 3-28, 3-48, 3-53, 3-85, 

39 3-105, 3-106, E-4 

40 Illinois Endangered Species Protection 

41 Board (IESPB)........................ xxxiii, 3-45, 3-107

42 Illinois Environmental Protection Agency 

43 (IEPA).... xxxiii, 3-8, 3-20, 3-25, 3-29, 3-30, 3-32, 

44 3-36, 3-37, 3-47, 3-106, 3-109, 3-110, 4-24, 

45 4-60, 4-90, 4-98, 4-101, 4-102, 4-106, 4-123, 

46 4-124, 4-127, A-3, A-4, A-8, A-9, B-1, B-8, B-9, 

47 D-2, E-3, E-5, E-6 

48 Illinois Historic Preservation Agency 

49 (IHPA)...........xxxiii, 1-6, 2-27, 3-65, 3-110, 4-46, 

50 4-47, 4-124, 4-126, 7-2, C-4, C-5, D-2 

51 Illinois State Geological Survey (ISGS) ..xxxiv, 

52 3-18, 3-107, 3-113

53 impingement...................... 3-8, 3-60, 4-38, 4-39

54 independent spent fuel storage installation 

55 (ISFSI)...........xxxiv, 3-13, 3-17, 3-18, 4-80, 4-81, 

56 4-108, 4-109

57 Indian tribes.......... 3-67, 3-91, 3-107, 4-71, 4-72

58 invasive species................................ 3-39, 4-95

59 L

60 long-term dose............................................ F-16

61 low-level waste.................................. 4-83, 4-86

62 M

63 Magnuson-Stevens Fishery Conservation 

64 and Management Act (MSA) ...... xxxv, 1-6, 1-7, 

65 1-8, 3-59, 3-65, 3-108, 4-43, 4-44, 4-81, 4-125, 

66 B-7, B-10, C-3, C-6 

67 Marine Mammal Protection Act 

68 (MMPA)................................................. xxxv, B-9 

69 mitigation.......... xxiv, xxxviii, 1-3, 1-4, 1-5, 4-16, 

70 4-39, 4-43, 4-48, 4-49, 4-50, 4-81, 4-99, 4-115, 

71 4-127, 5-1, A-6, A-7, F-30, F-34, F-41

72 mixed waste......................................... 3-9, 3-95

73 N

74 National Environmental Policy Act 

75 (NEPA)....xx, xxiv, xxxvi, 1-1, 1-7, 1-8, 2-1, 3-90, 

76 3-100, 4-5, 4-42, 4-47, 4-50, 4-51, 4-76, 4-77, 

77 4-79, 4-80, 4-81, 4-82, 4-105, 4-119, 4-120, 

78 4-125, 4-126, 5-1, 7-4, A-8, B-3, C-1, C-3, C-6 

79 National Historic Preservation Act...... xx, xxvi, 

80 xxxvi, 1-6, 1-7, 1-8, 2-5, 4-46, 4-47, 4-80, 4-81, 

81 4-125, B-7, B-10, C-3, C-4, C-6 

82 National Marine Fisheries Service 

83 (NMFS) .........xxxvi, 3-59, 3-64, 3-65, 4-41, 4-42, 

84 4-43, 4-44, 4-123, B-7, C-1, C-2, C-3, C-6 

85 National Pollutant Discharge Elimination 

86 System (NPDES) .........xvii, xix, xxxvi, 3-9, 3-15, 

87 3-27, 3-28, 3-29, 3-30, 3-31, 3-32, 3-87, 3-96, 

88 3-97, 3-106, 4-26, 4-27, 4-28, 4-29, 4-30, 4-31, 

89 4-39, 4-60, 4-102, 4-106, 4-114, 4-123, 4-124, 

90 A-8, A-9, B-1, B-5, B-8, B-9, E-3 

91 Native American tribes......... 3-67, 3-107, 4-71, 

92 4-72
Index

8-3 

1 no-action alternative .........v, xxvi, 2-1, 2-3, 2-4, 

2 2-25, 2-28, 4-2, 4-33, 4-38, 4-43, 4-50, 4-82, 

3 4-90, 4-102, 4-105, 4-116, 5-1 

4 nonattainment ..................................... 3-20, 4-6 

5 P

6 postulated accidents ........ 4-1, 4-62, 4-63, 4-72

7 power uprate...................................... F-18, F-44

8 R

9 radioactive nuclides................................... 3-10

10 radon .................................................... 3-9, 3-13

11 reactor.... xxiii, xxxvii, xxxviii, 2-1, 2-2, 2-3, 2-10, 

12 2-11, 2-29, 3-1, 3-5, 3-6, 3-8, 3-11, 3-13, 3-16, 

13 3-18, 3-29, 3-37, 3-65, 3-86, 3-95, 4-24, 4-38, 

14 4-46, 4-48, 4-50, 4-51, 4-62, 4-63, 4-64, 4-68, 

15 4-73, 4-76, 4-77, 4-78, 4-79, 4-80, 4-81, 4-82, 

16 4-87, 4-99, 4-107, 4-108, 4-109, 4-110, 4-118, 

17 A-5, A-6, A-7, E-2, E-5, E-6, E-7, F-7, F-9, F-15, 

18 F-16, F-18, F-23, F-26, F-32, F-34, F-36, F-38

19 refurbishment........... 2-2, 3-60, 3-65, 3-87, 4-5, 

20 4-27, 4-32, 4-50, 4-98, 4-100, 4-104, F-38

21 replacement power ...... v, xxvi, xxxviii, 2-3, 2-4, 

22 2-5, 2-6, 2-8, 2-18, 4-29, 4-50, 4-57, 4-71, 4-85, 

23 4-87, F-35, F-38

24 S

25 scoping.......v, xxiii, xxiv, xxvii, 1-1, 1-2, 1-6, 1-8, 

26 4-1, 4-6, 4-21, 4-23, 4-24, 4-31, 4-37, 4-47, 

27 4-51, 4-58, 4-63, 4-76, 4-86, 4-88, 4-97, 5-2, 

28 A-1, A-3, A-8, C-4, C-5 

29 seismic .......... xxxviii, 3-23, 4-65, F-1, F-4, F-10, 

30 F-14, F-26, F-40, F-44, F-47

31 severe accident mitigation alternative 

32 (SAMA) ...........xxi, xxvi, xxxviii, 4-63, 4-64, 4-65, 

33 4-66, 4-67, 4-68, 4-122, 6-2, D-3, D-4, F-1, F-2, 

34 F-3, F-5, F-8, F-9, F-10, F-11, F-13, F-14, F-17, 

35 F-18, F-19, F-20, F-21, F-22, F-23, F-24, F-25, 

36 F-26, F-27, F-28, F-29, F-34, F-35, F-36, F-37, 

37 F-39, F-40, F-41, F-42, F-43, F-45, F-47

38 severe accidents ... xxvi, xxxviii, 4-1, 4-62, 4-63, 

39 4-64, 4-66, 4-72, 4-122, F-1, F-10, F-21, F-34, 

40 F-37, F-38, F-39, F-45, F-47

41 solid waste....... xxvii, 2-5, 2-24, 3-9, 3-10, 3-13, 

42 3-14, 3-86, 3-95, 4-12, 4-81, 4-83, 4-86, B-1 

43 spent fuel ....... xxiv, xxxiv, 1-4, 3-13, 4-77, 4-78, 

44 4-79, 4-80, 4-82, 4-86, 4-87, 4-118, E-2, F-36

45 State Historic Preservation Office 

46 (SHPO)......... 3-67, 4-46, 4-47, 4-124, 4-126, 7-2 

47 stormwater... 3-16, 4-26, 4-27, 4-28, 4-29, 4-30, 

48 4-31, 4-32, 4-39, A-8, B-5 

49 surface runoff........ 3-27, 3-30, 3-47, 4-26, 4-27, 

50 4-28, 4-29, 4-30, 4-33, 4-93, 4-94, 4-95, 4-101, 

51 4-102, 4-103, 4-104, 4-106, 4-114, B-5 

52 surface water......... 3-25, 3-27, 3-28, 3-29, 3-32, 

53 3-36, 3-37, 3-50, 3-87, 4-22, 4-23, 4-24, 4-26, 

54 4-27, 4-28, 4-29, 4-30, 4-33, 4-38, 4-59, 4-72, 

55 4-73, 4-86, 4-95, 4-100, 4-101, 4-102, 4-114, 

56 B-1, B-5 

57 T

58 taxes...................... xxxvii, 3-80, 3-81, 3-82, 4-51

59 transmission line corridors ..... 4-5, 4-29, 4-34, 

60 4-35

61 transmission lines .......xxxviii, 2-11, 2-14, 2-15, 

62 2-16, 2-18, 3-1, 3-15, 3-22, 3-38, 3-40, 3-46, 

63 3-60, 3-65, 3-89, 3-101, 4-2, 4-4, 4-5, 4-6, 4-19, 

64 4-28, 4-29, 4-31, 4-34, 4-35, 4-36, 4-37, 4-39, 

65 4-40, 4-46, 4-48, 4-49, 4-50, 4-58, 4-61, 4-99

66 tritium............................... 3-36, 3-37, 4-25, 4-26

67 U

68 U.S. Department of Energy (DOE)......xxxi, 2-4, 

69 2-10, 2-12, 2-13, 2-14, 2-16, 2-17, 2-18, 2-19, 

70 2-20, 2-22, 2-23, 2-24, 2-28, 2-29, 2-30, 2-31, 

71 2-32, 2-34, 3-13, 4-10, 4-53, 4-54, 4-56, 4-59, 

72 4-91, 4-120, 4-125, 6-2 

73 U.S. Environmental Protection Agency 

74 (EPA) ..........xxxi, xxxiii, 1-1, 2-1, 2-4, 2-13, 2-23, 

75 2-24, 2-25, 2-28, 2-31, 3-5, 3-8, 3-9, 3-10, 3-11, 

76 3-12, 3-17, 3-20, 3-21, 3-23, 3-29, 3-36, 3-37, 

77 3-79, 3-86, 3-90, 3-95, 3-96, 3-97, 3-101, 3-102, 

78 3-106, 3-107, 3-109, 4-6, 4-9, 4-10, 4-11, 4-12, 

79 4-13, 4-14, 4-15, 4-25, 4-39, 4-60, 4-69, 4-70, 

80 4-76, 4-78, 4-89, 4-92, 4-93, 4-94, 4-98, 4-99, 

81 4-103, 4-105, 4-108, 4-111, 4-112, 4-115, 4-118, 

82 4-119, 4-120, 4-121, 4-123, 4-124, 5-1, 7-2, 7-4, 

83 7-5, A-8, A-9, B-1, B-3, B-4, B-5, B-6, B-9, E-3, 

84 E-5, E-6, F-19, F-45

85 U.S. Fish and Wildlife Service (FWS).......xxxii, 

86 1-6, 1-7, 2-10, 2-16, 2-34, 3-39, 3-40, 3-42, 

87 3-44, 3-45, 3-59, 3-60, 3-61, 3-62, 3-63, 3-64, 

88 3-96, 3-97, 3-98, 3-101, 3-104, 3-105, 3-107, 

89 3-109, 3-110, 3-111, 4-41, 4-42, 4-43, 4-122, 

90 4-123, 7-2, 7-3, 7-4, B-7, C-1, C-2, C-3, C-6 

91 uranium... 2-10, 3-5, 4-1, 4-69, 4-85, 4-86, 4-87, 

92 4-89
Index

8-4 

1 W

2 wastewater........ 3-10, 3-15, 3-37, 4-100, 4-101, 

3 4-102, A-8, E-3, E-5 

4 Y

5 Yucca Mountain ............................................ 4-78
1 APPENDIX A 

2 COMMENTS RECEIVED ON THE BYRON STATION

3 ENVIRONMENTAL REVIEW

A-1 

1 A. COMMENTS RECEIVED ON THE BYRON STATION

2 ENVIRONMENTAL REVIEW

3 A.1 Comments Received During the Scoping Period

4 The scoping process for the environmental review of the license renewal application for Byron 

5 Station Units 1 and 2 (Byron) began on August 6, 2013, with the publication of the U.S. Nuclear 

6 Regulatory Commission’s (NRC’s) notice of intent to conduct scoping in the Federal Register

7 (78 FR 47800). The scoping process included two public meetings held in Byron, Illinois, on 

8 August 20, 2013. Approximately 70 people attended the meetings. After the NRC’s prepared 

9 statements pertaining to the license renewal process, the meetings were open for public 

10 comments. Attendees provided oral statements that were recorded and transcribed by a 

11 certified court reporter. A summary and transcripts of the scoping meetings are available using 

12 the NRC’s Agencywide Documents Access and Management System (ADAMS). ADAMS 

13 Public Electronic Reading Room is accessible at http://www.nrc.gov/reading-rm/adams.html. 

14 The scoping meetings summary can be found under ADAMS Nos. ML13269A006 (package) 

15 and ML13240A234 (summary). Transcripts for the afternoon and evening meetings included in 

16 the meeting summary package (ML13269A006) can be found under ADAMS 

17 Nos. ML13266A183 and ML13266A182, respectively. In addition to comments received during 

18 the public meetings, comments were also received electronically and through the mail. 

19 Each commenter was given a unique identifier, so every comment can be traced back to its 

20 author. Table A–1 identifies the individuals who provided comments and an accession number 

21 to identify the source document of the comments in ADAMS.

22 Specific comments were categorized and consolidated by topic. Comments with similar specific 

23 objectives were combined to capture the common essential issues raised by commenters. 

24 Comments have been grouped into the following general categories:

25 • Specific comments that address environmental issues within the purview of 

26 the NRC environmental regulations related to license renewal. These 

27 comments address Category 1 (generic) or Category 2 (site-specific) issues 

28 identified in NUREG-1437, Generic Environmental Impact Statement for 

29 License Renewal of Nuclear Plants (GEIS) or issues not addressed in the

30 GEIS. The comments also address alternatives to license renewal and 

31 related Federal actions.

32 • General comments in support of or opposed to nuclear power or license 

33 renewal or comments regarding the renewal process, the NRC’s regulations, 

34 and the regulatory process.

35 • Comments that address issues that do not fall within or are specifically 

36 excluded from the purview of NRC environmental regulations related to 

37 license renewal. These comments typically address issues such as the need 

38 for power, emergency preparedness, security, current operational safety 

39 issues, and safety issues related to operation during the renewal period.
Appendix A

A-2 

1 Table A–1. Individuals Providing Comments During the Scoping Comment Period

2 Each commenter is identified along with their affiliation and how their comment was submitted.

Commenter Affiliation (if stated) ID Comment Source ADAMS Number

Chris Millard City of Byron, Mayor 001 Afternoon Scoping 

Meeting ML13269A006

Jared Funderburg

Representative for 

Congressman Kinzinger, 

Illinois, 16th District

002

013

Afternoon Scoping 

Meeting

Evening Scoping 

Meeting

ML13269A006

Russ Kearney Byron Site VP

003

015

Afternoon Scoping 

Meeting

Evening Scoping 

Meeting

ML13269A006

Mike Gallagher Exelon Vice President of 

License Renewal 

004

016

Afternoon Scoping 

Meeting

Evening Scoping 

Meeting

ML13269A006 

Ron Gibson Byron Township 005 Afternoon Scoping 

Meeting ML13269A006 

Tom Wolf Illinois Chamber of Commerce 006 Afternoon Scoping 

Meeting ML13269A006 

Sarah Fuller Byron employee 007 Afternoon Scoping 

Meeting ML13269A006 

Michael Harn Sheriff of Ogle County 008 Afternoon Scoping 

Meeting ML13269A006 

Doug O’Brien Illinois Clean Energy Coalition 

009

017

Afternoon Scoping 

Meeting

Evening Scoping 

Meeting

ML13269A006 

Todd Tucker Executive Director of the 

Byron Forest Preserve 010 Afternoon Scoping Meeting ML13269A006 

Allen Christianson Exelon 011 Afternoon Scoping 

Meeting ML13269A006 

Jenny Beckman Director of United Way of Ogle 

County 012 Afternoon Scoping Meeting ML13269A006 

Tom Demmer State Representative 014 Evening Scoping 

Meeting ML13269A006 

Ron Colson Blackhawk Hills Regional 

Council 018 Evening Scoping Meeting ML13269A006 

Charles Medrano Byron employee 019 Evening Scoping 

Meeting ML13269A006 
Appendix A

A-3 

Commenter Affiliation (if stated) ID Comment Source ADAMS Number

Dan Westin Rochelle Utilities 020 Evening Scoping 

Meeting ML13269A006 

Ronald Bolin Exelon 021 Evening Scoping 

Meeting ML13269A006 

Kim Gouker Ogle County Board 

022

026

Evening Scoping 

Meeting

Letter

ML13269A006

ML13263A221 

Brent Baker Byron Chamber and Employee 

of the Byron Bank 023 Evening Scoping Meeting ML13269A006 

Bruce Drawbridge Vice President with CB&I, 

Chicago Bridge and Iron 024 Evening Scoping Meeting ML13269A006 

David Kraft Nuclear Energy Information 

Service 

025

027

Evening Scoping 

Meeting

Letter 

ML13269A006

ML13277A306 

Alan Keller Illinois Environmental 

Protection Agency 028 Letter ML14113A544

1 Comments that are general or outside the scope of the environmental review for Byron license 

2 renewal are not included here but can be found in the Scoping Summary Report (ADAMS 

3 No. ML14041A334). To maintain consistency with the Scoping Summary Report, the unique 

4 identifier used in that report for each comment is retained in this Appendix A with one exception. 

5 One comment was originally placed under Meteorology, Air Quality, and Noise. During the 

6 development of the draft SEIS, the comment was addressed better under Climate Change. 

7 Comments addressed in this Appendix A are provided at the end of the Scoping Summary 

8 Report.

9 Comments received during the scoping comment period applicable to this environmental review 

10 were placed into categories, which are based on topics contained in the Byron draft 

11 supplemental environmental impact statement (DSEIS). These categories and their 

12 abbreviation codes are listed in Table A–2.

13 Table A-2 also includes a comment from the Illinois Environmental Protection Agency

14 concerning the renewal of the Byron Station that was received outside of the scoping period. 

15 Table A–2. Issue Categories

16 Comments were divided into the categories below, each with a unique abbreviation code.

Code Technical Issue

CC Climate Change (formerly, Meteorology, Air 

Quality, and Noise)

AL Alternatives to License Renewal of Byron 

SO Socioeconomic Impact of Byron 

SW Water Resource – Surface Water
Appendix A

A-4 

1 The following pages contain the comments, identified by the commenter’s ID, comment number,

2 and comment issue category, and the NRC staff response. Comments are presented in the 

3 same order as listed in Table A–2. 

4 A.1.1. Climate Change (CC) (formerly Meteorology, Air Quality, and Noise (ME))

5 Comment: 

6 027-2 CC - The ER submitted by Exelon is incomplete in not providing evidence that it has 

7 examined the projected effects of predicted Illinois climate disruption on future operations. NRC 

8 regulations are inadequate for not requiring this examination.

9 Current climate models suggest that Illinois will gradually assume a climate resembling that of 

10 East Texas or Mississippi by mid-Century (within the period of operational life extension of 

11 Byron), depending on whether one is running a low- or high- emissions model. Summer 

12 temperatures are expected to increase on average from 3.30 to 8.60 F. While total precipitation 

13 is expected to remain about the same, seasonal variation will increase, and frequency of heavy 

14 precipitation events-measured in terms of number of days per year with more than 2 inches of 

15 rain, and annual maximum 24-hr, 5-day and 7-day rainfall totals-is likely to continue to increase, 

16 particularly closer to the Great Lakes, a factor which will have implications in the Comments 

17 below.

18 The implications of these projections do not seem to be incorporated into the ER analysis 

19 provided by Exelon, which invariably result in the conclusion of “small” impact. The ER clearly 

20 states that the Rock River is a “small river” by definition. Make-up water for the mechanical draft 

21 cooling tower system relies on the Rock River. Decreased volume and flow rates expected 

22 under projected climate disruption models for Illinois could have an adverse effect on the 

23 MDCT’s ability to function. Since this system is dedicated to cooling the safety-related portions 

24 of the plant, this could have serious consequences; but this is not evidenced in the conclusions 

25 Exelon arrives at.

26 Exelon’s historic penchant to request license variances on water use and thermal discharge (not 

27 a factor at Byron) from IEPA suggests the possibility for greater effect than is characterized in 

28 the Exelon ER document. The alternative would be curtailment of operation, which also does 

29 not appear factored into the Exelon ER in any manner.

30 Recommendation: NRC should require a more thorough projection of water use at Byron, based 

31 on the best possible climate modeling for Illinois between now and mid-century. Because this 

32 variation in climate disruption and its effects are local/regional, it falls outside the scope of a 

33 generic analysis or regulation.

34 Response: This comment expresses concern over climate change projections and impacts as 

35 a result of climate change on operations of Byron. The commenter specifically identifies 

36 averaged climate change projections provided in the 2009 U.S. Global Climate Change 

37 Research Program report and Hayhoe et al. 2010 for Illinois for the 2040 through 2059 

38 timeframe and 2080 to 2099 timeframe. The NRC has evaluated the potential impacts of 

39 climate change upon the affected resources during the Byron license renewal term (2024 

40 through 2044 for Unit 1 and 2026 through 2046 for Unit 2) in Section 4.15.3, “Greenhouse Gas 

41 Emissions and Climate Change,” of this draft SEIS. 

42 In informing potential climate change impacts, the NRC staff utilized, among various resources, 

43 consensus information from both the 2009 and most recent 2014 U.S. Global Change Research 

44 Program report and the National Oceanic and Atmospheric Administration’s 2013 climate 

45 change report. Section 4.15.3 of the SEIS discusses climate projections for the 2021 through 

46 2050 timeframe, which is appropriate given Byron’s license renewal term. Section 4.15.3 
Appendix A

A-5 

1 describes the temperature and precipitation trends in the Midwest region, where Byron is 

2 located. Specifically, for the license renewal period of Byron and for the State of Illinois, climate 

3 model simulations (from 2021 and 2050 relative to the reference period (1971 to 1999)) indicate 

4 an increase in annual mean temperature in the Midwest region from 2.5 to 3.5 °F (1.5 to 2.1°C), 

5 an increase in summertime mean temperatures of 3 °F (1.6 °C), and a 0 to 3 percent increase in 

6 annual mean precipitation with fall, winter, and spring seasons experiencing precipitation 

7 change increases and the summer season experiencing a decrease in precipitation. However, 

8 these changes in precipitation were not significant, and the models indicate changes that are 

9 less than normal year-to-year variations and projected summertime temperature increases 

10 displayed a wide range in temperature ranging in an increase of 1.5 to 5.5 °F (0.76 to 2.98°C)

11 (Kunkel et al. 2013). 

12 Potential climate change impacts to water resources are discussed in Section 4.15.3.2, the 

13 impacts to the Rock River frorm continued operation in Section 4.5.1, and climate change 

14 impacts specific to the Rock River in Section 4.16.3.1. However, the impacts of climate change 

15 on operations and safety at Byron, as the commenter raises, are addressed as part of the 

16 NRC’s ongoing reactor oversight process. The NRC evaluates new information that could affect 

17 the safety of operating nuclear power plants, such as changes in the operating environment, on 

18 an ongoing basis to determine if any changes are needed at existing plants. This ongoing 

19 reactor oversight process is separate and distinct from the license renewal process, which is 

20 focused on managing the effects of aging on systems, structures, and components during the 

21 period of extended operation. 

22 Concerns about the adequacy of NRC regulations may be raised in a petition that asks the NRC 

23 to develop, change, or rescind a rule by filing a petition for rulemaking in accordance with the 

24 regulations in Title 10 of the Code of Federal Regulations (10 CFR) 2.802, “Petition for 

25 rulemaking.” Before filing a petition for rulemaking, a potential rulemaking petitioner may 

26 consult with the NRC concerning questions about NRC regulations and rulemaking petition 

27 procedures by calling the Rules and Directives Branch at 301-415-7163 or toll-free at 

28 800-368-5642 or by writing to the following address:

29 Chief

30 Rules and Directives Branch

31 Division of Administrative Services

32 Office of Administration

33 U.S. Nuclear Regulatory Commission

34 Washington, DC 20555-0001

35 A.1.2. Socioeconomic Impact of Byron (SO)

36 Comment: 

37 027-3 SO Analysis of socio-economic impacts are incomplete. No analysis of impacts of early 

38 or unexpected closure are considered or provided.

39 The Exelon ER documents a significant tax impact for the presence of the Byron Nuclear 

40 Station, yet only addresses the positive impacts. No mention or analysis of negative impacts 

41 resulting from abrupt, planned, or unexpected early closure of Byron is presented. This is a 

42 significant omission. 

43 According to the Exelon ER Byron represents nearly 26% of the Ogle County total tax base, 

44 roughly $30 million annually for the years 2008 through 2010. It also accounts for upwards of 

45 73% of Byron Unit 226 School District’s adjusted property tax levy. These are not insignificant 
Appendix A

A-6 

1 amounts. Their abrupt disappearance would wreak economic havoc on the affected 

2 governmental and essential service entities’ ability to operate.

3  The ER either fails to recognize or mention at all some of the possible events 

4 that could result in such a situation:

5  Unexpected major accident, resulting in immediate and presumably 

6 premature closure

7  NRC ordered shut down

8  Exelon’s unilateral decision to close the plant on economic or other grounds, 

9 as it did at Zion, resulting in an immediate loss of about 55% of Zion’s tax 

10 base

11  Devaluation through sale, as occurred at the Clinton station, resulting in 

12 enormous loss of tax base

13  Eventual old-age, license expiration closure (the outcome most hoped for)

14 Exelon even provides a possible indication of the kinds of circumstances that would lead it to 

15 close Byron on economic grounds. Section 3.2 on Refurbishment indicates that Exelon is well 

16 aware that Byron Unit 2 may need a steam generator replacement during the extended 

17 operational lifetime. It is also tracking the potential for reactor vessel head replacements at its 

18 operating PWRs at both Byron and Braidwood. Should either or both of these conditions 

19 emerge at a time of deflated energy prices, or at a time Exelon acknowledges might occur as 

20 early as 2024 when renewables are much more cost competitive and approaching base load 

21 capabilities (Sec. 7.2, page 7-9), or as the result of multi-season drought curtailing water 

22 availability - Exelon being a business will certainly make the calculations it made when it closed 

23 Zion, and decide if Byron should continue to operate.

24 In this omission the ER makes the same mistake the U.S. Government made when it invaded 

25 Iraq - it had no exit strategy. To simply assume that the only socio-economic effects of Byron’s 

26 presence will be positive ones is simply irrational.

27 Recommendation: Planning for some kind of eventual closure must be made long before it 

28 happens to minimize economic and service disruptions to the entities whose tax base will be 

29 affected. Debate about the license extension serves as a good reminder of this fact, and an 

30 opportunity to take action. We recommend that dependent govemmental and taxing entities 

31 begin formal negotiations with Exelon to establish an escrowed “closure mitigation fund,” based 

32 on some mutually agreeable assessment and payment structure, so that dependent entities will 

33 have some kind of temporary funds available to soften the economic blow of closure, and not 

34 radically disrupt essential services.

35 Response: With the exception of an unexpected major accident and NRC-ordered shutdown 

36 for safety reasons, the possible events leading to the closure of Byron identified in this comment 

37 involve energy planning decisions that would be made by Exelon and state officials. The NRC 

38 has no role in these energy planning decisions. Also, the closure of Byron could occur at any 

39 time, including upon the expiration of either the current or renewed operating license.

40 Information about Exelon’s tax payments is described in Section 3.10.5, “Tax Revenue” in the 

41 draft SEIS, and the socioeconomic impacts of station closure and the termination of reactor

42 operations caused by the expiration of the Byron operating license is described as part of the 

43 “no action” alternative in the socioeconomic impacts of license renewal section in Chapter 4 in 

44 the draft SEIS, specifically Section 4.10.2. The impacts of closing and decommissioning a 

45 nuclear power plant are also described in the “Generic Environmental Impact Statement on 

46 Decommissioning of Nuclear Facilities: Regarding the Decommissioning of Nuclear Power 
Appendix A

A-7 

1 Reactors” (NUREG–0586) (NRC 2002). The environmental consequences of decommissioning 

2 Byron itself would be during decommissioning.

3 In regards to what is to be discussed in the ER, 10 CFR 51.45(c) states, 

4 Environmental reports prepared at the license renewal stage under §51.53(c) 

5 need not discuss the economic or technical benefits and costs of either the 

6 proposed action or alternatives except if these benefits and costs are either 

7 essential for a determination regarding the inclusion of an alternative in the range 

8 of alternatives considered or relevant to mitigation. In addition, environmental 

9 reports prepared under §51.53(c) need not discuss issues not related to the 

10 environmental effects of the proposed action [license renewal] and its 

11 alternatives.

12 In Section 4.10.2, “No-Action Alternative,” under socioecomic impacts, the NRC 

13 determined that not renewing the operating licenses and terminating reactor operations 

14 could have a noticeable impact on socioeconomic conditions in the communities located 

15 near Byron. Specifically, there would be the loss of jobs and income for individuals

16 working at or providing services to Byron, as well as reduced tax revenue in affected tax 

17 jurisdictions from the termination of power plant operations. These socioeconomic 

18 impacts could range from SMALL to LARGE, depending on the jurisdiction.

19 A.1.3. Alternatives to License Renewal of Byron (AL)

20 Comment:

21 027-5 AL Recommendation: Order Exelon to re-examine its Section 7 comparisons, 

22 incorporating: 2.) better data on the capabilities of wind and solar, based on expected 

23 improvements in technology, or better and more optimal use decisions...

24 Response: Chapter 2 of the draft SEIS describes the alternatives that are discussed further in 

25 Chapter 4 and describes the alternatives that were considered but dismissed. 

26 Specifically, in evaluating alternatives to license renewal, the NRC staff first selects energy 

27 technologies or options currently in commercial operation, as well as some technologies not 

28 currently in commercial operation but likely to be commercially available by the time the current 

29 Byron operating licenses expire in 2024 and 2026.

30 Second, the NRC staff screens the alternatives to remove those that cannot meet future system 

31 needs. Then, the remaining options are screened to remove those alternatives whose costs or 

32 benefits do not justify inclusion in the range of reasonable alternatives. Any alternatives 

33 remaining, then, constitute alternatives to the proposed action that the NRC staff evaluates in 

34 depth throughout Chapter 4.

35 In Section 2.3.2, solar power was considered as a potential alternative, but dismissed because 

36 the NRC staff considers it unlikely that current solar power technologies could serve as 

37 baseload power sufficient to replace Byron’s output. In Section 2.3.4, wind power was 

38 considered as a potential alternative, but dismissed as unreasonable given the amount of wind 

39 capacity necessary to replace Byron and the intermittency of wind power. Solar and wind power 

40 were considered in combination with a natural gas combined-cycle facility. This combination 

41 alternative is described in Section 2.2.2.4 and the impact of this combination alternative is 

42 described under each resource area in Chapter 4. 
Appendix A

A-8 

1 A.1.4. Water Resources - Surface Water (comment not identified in scoping summary 

2 report)

3 Comment:

4 028-1 SW This Agency received a request on July 5, 2012 from Exelon Generating Company 

5 requesting necessary comments concerning the renewal of the Nuclear Regulatory Commission 

6 operating licenses for the Byron Generating Stations Units 1 and 2 in Ogle County. We offer the 

7 following comments. 

8 This Agency hereby issues certification under Section 401 of the Clean Water Act (PL 95-217), 

9 subject to the applicant’s compliance with the following conditions:

10 (1) The applicant shall be responsible for obtaining NPDES permits required for wastewater or 

11 stormwater discharges to waters of the State from the proposed activity.

12 (2) This certification does not cover future activities that require a federal authorization under 

13 Section 404 of the Clean Water Act.

14 This certification becomes effective when the Nuclear Regulatory Commission includes the 

15 above conditions # 1 through # 2 as conditions of the requested license issued under the Atomic 

16 Energy Act of 1954.

17 This certification does not grant immunity from any enforcement action found necessary by this 

18 Agency to meet its responsibilities in prevention, abatement, and control of water pollution.

19 Response: This comment provided input (or data) for the staff’s environmental analysis of 

20 water resource impacts of Byron on local and regional communities. This comment addresses 

21 Clean Water Act (CWA) Section 401 certification of the Byron discharge. The staff discusses 

22 water resource impacts, specifically the Section 401 certification in Section 3.5.1 of Chapter 3 of 

23 the SEIS.

24 On May 12, 2014, Exelon updated its application (Exelon 2014) to inform the staff that by letter 

25 to the NRC dated July 5, 2013 (IEPA 2014), the IEPA issued the CWA Section 401 certification 

26 for Byron operation during the license renewal.

27 The NRC understands the importance of the CWA and a delegated State’s role in implementing 

28 the statute. As early as 1984, the Commission recognized that in revising its regulations, NRC 

29 licenses are subject to conditions deemed imposed by the CWA as a matter of law and that the 

NRC need not duplicate EPA’s or a delegated State agency’s water quality reviews.14 30 To 

31 explicitly recognize that conditions are deemed imposed by the CWA and to remove the need to 

32 undertake amendments to incorporate conditions imposed by statute that could be subject to 

frequent changes by certifying States, the Commission added 10 CFR 50.54(aa)15 33 to specifically 

34 provide that each 10 CFR Part 50 “license shall be subject to all conditions deemed imposed as 

35 a matter of law by section 401(a)(2) and 401(d) of the CWA (33 U.S.C.A. 1341(a)(2) and (d)), as 

36 amended).” To keep informed of the environmental effects of NRC licensing actions, the 

37 Commission relies on reporting requirements of National Pollutant Discharge Elimination 

38 System (NPDES) permits to alert the NRC of environmental effects of NRC licensing action. As 

39 the Commission stated, “The NRC’s role in the water quality area is limited to regulating 

40 radiological discharges into aquatic bodies and NEPA matters such as weighing aquatic impacts 

 

1449 FR. 9352, 9359-60. “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions and 

Related Conforming Amendments.” March 12, 1984.

1549 FR. 9352, 9360.
Appendix A

A-9 

1 in NEPA analyses which NRC is required to make before reaching a major Federal licensing 

decision.”16 2 

3 Because the two 401 certification conditions are license requirements either because they are 

4 imposed as a matter of law or they state existing statutory provisions, no further NRC action is 

5 needed with respect to these two conditions. Specifically, (1) Exelon must obtain a CWA 

6 Section 402 (NPDES) permit from the State in accordance with 33 U.S.C. § 1342, and 

7 (2) a 401 certification does not authorize activities that require an authorization under 

8 Section 404 of the CWA, 33 U.S.C. § 1344 (i.e., the permits for discharges of dredged or fill

9 material, which are issued by the U.S. Army Corps of Engineers). Appendix B, paragraph 3.2 of 

10 the current Byron licenses further requires that Exelon provide the NRC copies of any NPDES 

11 permit or State certification (or changes to those documents) within 30 days of approval. If the 

12 licenses are renewed, this requirement will be carried over to the renewed licenses for Byron

13 Units 1 and 2. 

14 A.2 References

15 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

16 protection regulations for domestic licensing and related regulatory functions.”

17 78 FR 47800. U.S. Nuclear Regulatory Commission. “License Renewal Application for Byron 

18 Station, Units 1 and 2; Exelon Generation Company, LLC.” Federal Register

19 78(151):47800-47802. August 6, 2013.

20 [Exelon] Exelon Generation Company, LLC. 2013. Byron Station, Units 1 and 2, License 

21 Renewal Application, Appendix E, Applicant’s Environmental Report, Operating License 

22 Renewal Stage. May 29, 2013. Agencywide Documents Access and Management System 

23 (ADAMS) Nos. ML13155A422 and ML13155A423.

24 [Exelon] Exelon Generating Company, LLC. 2014, Update to Chapter 9 of Byron and 

25 Braidwood Stations, Units 1 and 2 License Renewal Application, Byron Station Applicant’s 

26 Environmental Report. May 12, 2014. ADAMS No. ML14132A141.

27 [IEPA] Illinois Environmental Protection Agency. 2014. Illinois Environmental Protection Agency, 

28 Certification under Section 401 of the Clean Water Act (CWA). July 5, 2014. ADAMS 

29 No. ML14113A544.

30 Kunkel KE, Stevens LE, Stevens SE, Sun L (North Carolina State University and National 

31 Climatic Data Center), Janssen E, Wuebbles D, Hilberg SD, Timlin MS, Stoecker L, 

32 Westcott NE (University of Illinois at Urbana–Champaign), et al. 2013. Regional Climate Trends 

33 and Scenarios for the U.S. National Climate Assessment, Part 3. Climate of the Midwest U.S. 

34 Washington, DC: National Oceanic and Atmospheric Administration (NOAA). NOAA Technical 

35 Report NESDIS 142-3. January 2013. 103 p. Available at 

36 <http://www.nesdis.noaa.gov/technical_reports/

37 NOAA_NESDIS_Tech_Report_142-3-Climate_of_the_Midwest_U.S.pdf>.

38 Melillo JM (Marine Biological Laboratory), Richmond TC (Van Ness Feldman, LLP), Yohe GW 

39 (Wesleyan University), editors. 2014. Climate Change Impacts in the United States: The Third 

40 National Climate Assessment. Washington, DC: U.S. Global Change Research Program. 

41 May 2014. 841 p. ADAMS No. ML14129A233.

 

1649 FR. 9352, 9380.
Appendix A

A-10

1 [NRC] U.S. Nuclear Regulatory Commission. 2002. Generic Environmental Impact Statement

2 for Decommissioning of Nuclear Facilities, Supplement 1: Regarding the Decommissioning of 

3 Nuclear Power Reactors. NUREG-0586, Supplement 1, Vols. 1 and 2. Office of Nuclear 

4 Reactor Regulation, Washington, D.C. November 2002. ADAMS Nos. ML023470327, 

5 ML023500228, ML023470304, ML023500295. 

6 [NRC] U.S. Nuclear Regulatory Commission. 2013. Generic Environmental Impact Statement

7 for License Renewal of Nuclear Plants. Washington, DC: NRC. NUREG–1437, Revision 1. 

8 June 30, 2013. ADAMS No. ML13107A023.

9 [NRC] U.S. Nuclear Regulatory Commission. 2014. Summary Of Public Scoping Meetings 

10 Conducted Related To The Review Of The Byron Nuclear Station, License Renewal Application 

11 (TAC NOS. MF1790 AND MF1791). February 7, 2014. ADAMS No. ML13269A006
1 APPENDIX B 

2 APPLICABLE LAWS, REGULATIONS, AND OTHER REQUIREMENTS

B-1 

1 B. APPLICABLE LAWS, REGULATIONS, AND OTHER 

2 REQUIREMENTS

3 There are a number of Federal laws and regulations that affect environmental protection, health, 

4 safety, compliance, and consultation at every nuclear power plant licensed by the U.S. Nuclear 

5 Regulatory Commission (NRC). Certain Federal environmental requirements have been 

6 delegated to state authorities for enforcement and implementation. Furthermore, states have 

7 also enacted laws to protect public health and safety and the environment. It is the NRC’s policy 

8 to ensure nuclear power plants are operated in a manner that provides adequate protection of 

9 public health and safety and protection of the environment through compliance with applicable 

10 Federal and state laws, regulations, and other requirements.

11 The requirements that may be applicable to the operation of NRC-licensed nuclear power plants 

12 encompass a broad range of Federal laws and regulations, addressing environmental, historic 

13 and cultural, health and safety, transportation, and other concerns. Generally, these laws and 

14 regulations are relevant to how the work involved in performing a proposed action would be 

15 conducted to protect workers, the public, and environmental resources. Some of these laws 

16 and regulations require permits or consultation with other Federal agencies or state, tribal, or 

17 local governments.

18 The Atomic Energy Act of 1954 (as amended) (AEA) (42 United States Code (U.S.C.) § 2011 et 

19 seq.) authorizes the U.S. Nuclear Regulatory Commission (NRC) to enter into agreement with 

20 any state to assume regulatory authority for certain activities (see 42 U.S.C. § 2021). For 

21 example, through the Agreement State Program, Illinois assumed regulatory responsibility over 

22 certain byproduct, source, and quantities of special nuclear materials not sufficient to form a 

23 critical mass. The Illinois Emergency Management Agency (IEMA), Division of Nuclear Safety 

24 administers several programs to protect citizens and the environment, including: a 

25 comprehensive monitoring system for the 11 operating nuclear power reactors in Illinois, 

26 inspection and regulation of radioactive materials licensees and x-ray machines, and oversight 

27 of cleanup efforts at sites contaminated with radioactive materials (IEMA undated).

28 In addition to carrying out some Federal programs, state legislatures develop their own laws. 

29 State statutes supplement, as well as implement, Federal laws for protection of air, water 

30 quality, and groundwater. State legislation may address solid waste management programs, 

31 locally rare or endangered species, and historic and cultural resources.

32 The Clean Water Act (33 U.S.C. § 1251 et seq., herein referred to as CWA) allows for primary 

33 enforcement and administration through state agencies, given that the state program is at least 

34 as stringent as the Federal program. The state program must conform to the CWA and to the 

35 delegation of authority for the Federal National Pollutant Discharge Elimination System

36 (NPDES) program from the U.S. Environmental Protection Agency (EPA) to the state. The 

37 primary mechanism to control water pollution is the requirement for direct dischargers to obtain 

38 an NPDES permit, or, as is the case for Illinois, the authority has been delegated from the EPA, 

39 a State Pollutant Discharge Elimination System permit, under the CWA. 

40 One important difference between Federal regulations and certain state regulations is the 

41 definition of waters regulated by the state. Certain state regulations may include underground 

42 waters, whereas the CWA only regulates surface waters. The Illinois Environmental Protection 

43 Agency (IEPA) Bureau of Water, Water Pollution Control conducts the numerous programs, 

44 including permit programs and surface water quality monitoring and assessment programs, to 

45 protect and enhance the quality of the state’s surface waters (IEPA undated). 
Appendix B

B-2 

1 B.1. Federal and State Requirements 

2 Byron Station, Units 1 and 2 are subject to Federal and State requirements. Table B–1 lists the 

3 principal Federal and State regulations and laws that are used or mentioned in this 

4 supplemental environmental impact statement (SEIS) for the Byron Nuclear Station.
Appendix B

B-3 

1 Table B–1. Federal and State Requirements

Law/regulation Requirements

Current operating license and license renewal

Atomic Energy Act (AEA), 

42 U.S.C. § 2011 et seq.

The 1954 Atomic Energy Act (AEA), as amended, and the Energy 

Reorganization Act of 1974 (42 U.S.C. 5801 et seq.) give the NRC the 

licensing and regulatory authority for nuclear energy uses within the 

commercial sector. These regulations give the NRC responsibility for 

licensing and regulating commercial uses of atomic energy and allow the 

NRC to establish dose and concentration limits for protection of workers 

and the public for activities under NRC jurisdiction. The NRC implements 

its responsibilities under the AEA through regulations set forth in Title 10 

of the Code of Federal Regulations (10 CFR).

National Environmental 

Policy Act of 1969, as 

amended (NEPA). 

42 U.S.C. 4321, et seq.

The National Environmental Policy Act (NEPA) requires Federal agencies 

to integrate environmental values into their decisionmaking process by 

considering the environmental impacts of proposed Federal actions and 

reasonable alternatives to those actions. NEPA establishes policy, sets 

goals (in Section 101), and provides means (in Section 102) for carrying 

out the policy. Section 102(2) contains action-forcing provisions to ensure 

that Federal agencies follow the letter and spirit of the Act. For major 

Federal actions significantly affecting the quality of the human 

environment, Section 102(2)(C) of NEPA requires Federal agencies to 

prepare a detailed statement that includes the environmental impacts of 

the proposed action and other specified information.

Title 10 of the Code of 

Federal Regulations

(10 CFR), Energy, Part 51

Regulations in 10 CFR Part 51, “Environmental protection regulations for 

domestic licensing and related regulatory functions,” contain 

environmental protection regulations applicable to the NRC’s domestic 

licensing and related regulatory functions.

10 CFR Part 54

Regulations in 10 CFR Part 54, “Requirements for renewal of operating 

licenses for nuclear power plants,” govern the issuance of renewed 

operating licenses and renewed combined licenses for nuclear power 

plants licensed pursuant to Sections 103 or 104b of the AEA and Title II of 

the Energy Reorganization Act of 1974 (88 Stat. 1242). The regulations 

focus on managing adverse effects of aging. The rule is intended to 

ensure that important systems, structures, and components will maintain 

their intended functions during the period of extended operation.

10 CFR Part 50

Regulations in 10 CFR Part 50, “Domestic licensing of production and 

utilization facilities,” are NRC regulations issued under the AEA, as 

amended (68 Stat. 919), and Title II of the Energy Reorganization Act of 

1974 (88 Stat. 1242) to provide for the licensing of production and 

utilization facilities. This part also gives notice to all persons who 

knowingly supply—to any licensee, applicant, contractor, or 

subcontractor—components, equipment, materials, or other goods or 

services, that relate to a licensee’s or applicant’s activities subject to this 

part that they may be individually subject to NRC enforcement action for 

violation of 10 CFR 50.5.
Appendix B

B-4 

Law/regulation Requirements

Air quality protection

Clean Air Act (CAA),

42 U.S.C. § 7401 et seq.

The Clean Air Act (CAA) is intended to “protect and enhance the quality of 

the nation’s air resources so as to promote the public health and welfare 

and the productive capacity of its population.” The CAA establishes 

regulations to ensure maintenance of air quality standards and authorizes 

individual states to manage permits. Section 118 of the CAA requires 

each Federal agency, with jurisdiction over properties or facilities engaged 

in any activity that might result in the discharge of air pollutants, to comply 

with all Federal, state, inter-state, and local requirements with regard to 

the control and abatement of air pollution. Section 109 of the CAA directs 

the U.S. Environmental Protection Agency (EPA) to set National Ambient 

Air Quality Standards (NAAQS) for criteria pollutants. The EPA has 

identified and set NAAQS for the following criteria pollutants: particulate 

matter, sulfur dioxide, carbon monoxide, ozone, nitrogen dioxide, and 

lead. Section 111 of the CAA requires establishment of national 

performance standards for new or modified stationary sources of 

atmospheric pollutants. Section 160 of the CAA requires that specific 

emission increases must be evaluated before permit approval to prevent 

significant deterioration of air quality. Section 112 requires specific 

standards for release of hazardous air pollutants (including radionuclides). 

These standards are implemented through plans developed by each state 

and approved by the EPA. The CAA requires sources to meet standards 

and obtain permits to satisfy those standards. Nuclear power plants may 

be required to comply with the CAA Title V, Sections 501–507, for sources 

subject to new source performance standards or sources subject to 

National Emission Standards for Hazardous Air Pollutants. Emissions of 

air pollutants are regulated by the EPA in 40 CFR Parts 50 to 99.

Illinois Administrative Code 

(IAC), Title 35, 

“Environmental Protection,” 

Subtitle B, “Air Pollution,” 

Chapter I, “Pollution Control 

Board,” Subchapter a, 

“Permits and General 

Provisions,” Part 201, 

“Permits and General 

Provisions”

This part of the IAC sets standards for air emissions from auxiliary boilers, 

emergency generators, radwaste volume reduction system, cooling 

towers, and ancillary operations.
Appendix B

B-5 

Law/regulation Requirements

Water resources protection

Clean Water Act (CWA),

33 U.S.C. § 1251 et seq., 

and the NPDES

(40 CFR 122)

The CWA was enacted to “restore and maintain the chemical, physical, 

and biological integrity of the Nation’s water.” The Act requires all 

branches of the Federal Government, with jurisdiction over properties or 

facilities engaged in any activity that might result in a discharge or runoff of 

pollutants to surface waters, to comply with Federal, state, inter-state, and 

local requirements. As authorized by the CWA, the National Pollutant 

Discharge Elimination System (NPDES) permit program controls water 

pollution by regulating point sources that discharge pollutants into waters 

of the United States. The NPDES program requires all facilities that 

discharge pollutants from any point source into waters of the United States 

to obtain an NPDES permit. A nuclear power plant may also participate in 

the NPDES General Permit for Industrial Stormwater due to stormwater

runoff from industrial or commercial facilities to waters of the United 

States. EPA is authorized under the CWA to directly implement the 

NPDES program; however, EPA has authorized many states to implement 

all or parts of the national program. Section 401 of the CWA requires 

states to certify that the permitted discharge would comply with all 

limitations necessary to meet established state water quality standards, 

treatment standards, or schedule of compliance. 

The U.S. Army Corps of Engineers is the lead agency for enforcement of 

CWA wetland requirements (33 CFR Part 320). Under Section 401 of the 

CWA, the EPA or a delegated state agency has the authority to review 

and approve, condition, or deny all permits or licenses that might result in 

a discharge to waters of the State, including wetlands.

Coastal Zone Management 

Act of 1972, as amended 

(16 U.S.C. 1451 et seq.)

Congress enacted the Coastal Zone Management Act (CZMA) in 1972 to 

address the increasing pressures of over-development upon the nation’s 

coastal resources. The National Oceanic and Atmospheric Administration 

administers the Act. The CZMA encourages states to preserve, protect, 

develop, and, where possible, restore or enhance valuable natural coastal 

resources such as wetlands, floodplains, estuaries, beaches, dunes, 

barrier islands, and coral reefs, as well as the fish and wildlife using those 

habitats. Participation by states is voluntary. To encourage states to 

participate, the CZMA makes Federal financial assistance available to any 

coastal state or territory, including those on the Great Lakes, that are 

willing to develop and implement a comprehensive coastal management 

program.

IAC, Title 35, 

“Environmental Protection,” 

Subtitle C, “Water Pollution,” 

Chapter I, “Pollution Control 

Board,” Part 309, “Permits”

This part of the Illinois Administrative Code implements the NPDES

program under CWA. 

Wild and Scenic Rivers Act, 

16 U.S.C. § 1271 et seq.

The Wild and Scenic River Act created the National Wild and Scenic 

Rivers System, which was established to protect the environmental values 

of free flowing streams from degradation by impacting activities, including 

water resources projects.

415 Illinois Compiled 

Statutes (ILCS) 5, 

“Environmental Protection 

Act,” Title III, “Water 

Pollution”

This part of the Illinois Compiled Statutes sets forth state standards for 

water pollution.
Appendix B

B-6 

Law/regulation Requirements

Waste management and pollution prevention

Resource Conservation and 

Recovery Act (RCRA), 

42 U.S.C. § 6901 et seq.

The Resource Conservation and Recovery Act (RCRA) requires the EPA

to define and identify hazardous waste; establish standards for its 

transportation, treatment, storage, and disposal; and require permits for 

persons engaged in hazardous waste activities. Section 3006 

(42 U.S.C. 6926) allows states to establish and administer these permit 

programs with EPA approval. EPA regulations implementing the RCRA 

are found in 40 CFR Parts 260 through 283. Regulations imposed on a 

generator or on a treatment, storage, and/or disposal facility vary 

according to the type and quantity of material or waste generated, treated, 

stored, and/or disposed. The method of treatment, storage, and/or 

disposal also impacts the extent and complexity of the requirements.

Pollution Prevention Act, 

42 U.S.C. § 13101 et seq.

The Pollution Prevention Act establishes a national policy for waste 

management and pollution control that focuses first on source reduction, 

then on environmental issues, safe recycling, treatment, and disposal.

10 CFR Part 20, 

Regulations in 10 CFR Part 20, “Standards for protection against 

radiation,” establish standards for protection against ionizing radiation 

resulting from activities conducted under licenses issued by the Nuclear 

Regulatory Commission. These regulations are issued under the AEA and 

the Energy Reorganization Act of 1974, as amended.

The purpose of these regulations is to control the receipt, possession, use, 

transfer, and disposal of licensed material by any licensee in such a 

manner that the total dose to an individual (including doses resulting from 

licensed and unlicensed radioactive material and from radiation sources 

other than background radiation) does not exceed the standards for 

protection against radiation prescribed in the regulations in this part.

IAC Title 35, “Environmental 

Protection,” Subtitle G, 

“Waste Disposal,” Chapter I, 

“Pollution Control Board,” 

Subchapter c, “Hazardous 

Waste Operating 

Requirements,” Part 722, 

“Standards Applicable to 

Generators of Hazardous 

Waste”

This part of the IAC establishes standards for generators of hazardous 

waste.

IAC Title 35, “Environmental 

Protection,” Subtitle C, 

“Water Pollution,” Chapter II, 

“Environmental Protection 

Agency,” Part 391, “Design 

Criteria for Sludge 

Application on Land”

This part of the IAC presents criteria for transporting, storing, and applying 

sludge on land in an environmentally acceptable manner. In addition, it 

identifies methods of sludge transportation, handling, storage, application 

and monitoring to control potential environmental problems. 
Appendix B

B-7 

Law/regulation Requirements

IAC Title 32, “Energy,” 

Chapter II, “Illinois 

Emergency Management 

Agency,” Subchapter d, 

“Low Level Radioactive 

Waste/Transportation,” 

Part 609, “Access to 

Facilities for Treatment, 

Storage, or Disposal of 

Low-Level Radioactive 

Waste” 

This part of the IAC establishes one of the systems for the regulation of 

the use of facilities in the State of Illinois to: (1) collect, store, treat or 

dispose of low-level radioactive waste; (2) maintain a data base as to the 

location of all such waste in the State of Illinois; and (3) implement some 

of the requirements, prohibitions and mandates of the Compact, the 

Radioactive Waste Compact Enforcement Act [45 ILCS 141], the 

Radioactive Waste Tracking and Permitting Act [420 ILCS 37] and the 

Illinois Low-Level Radioactive Waste Management Act [420 ILCS 20]. 

This Part establishes a system for monitoring and tracking shipments of 

low-level radioactive waste into, out of or within the State of Illinois for the 

purpose of tracking the points of origin of the shipments, as transported to 

the places of destination of the shipments. This Part establishes an 

enforcement and verification system directed to the movements of lowlevel radioactive waste into, out of or within the State of Illinois. This Part 

applies to any generator, broker, owner or operator of any treatment or 

disposal facility, or to any person who sends low-level radioactive waste 

into, within or out of the State of Illinois. 

Protected species

Endangered Species Act

(ESA), 16 U.S.C. § 1531 

et seq.

The Endangered Species Act (ESA) was enacted to prevent the further 

decline of endangered and threatened species and to restore those 

species and their critical habitats. Section 7 of the Act requires Federal 

agencies to consult with the U.S. Fish and Wildlife Service or the National 

Marine Fisheries Service (NMFS) on Federal actions that may affect listed 

species or designated critical habitats.

Magnuson–Stevens Fishery 

Conservation and 

Management Act (MSA), 

(16 U.S.C. §§ 1801-1884) 

as amended 

The Magnuson-Stevens Fishery Conservation and Management Act 

(MSA) governs marine fisheries management in U.S. Federal waters. The 

Act created eight regional fishery management councils and includes 

measures to rebuild overfished fisheries, protect essential fish habitat, and 

reduce bycatch. Under Section 305 of the Act, Federal agencies are 

required to consult with NMFS for any Federal actions that may adversely 

affect essential fish habitat.

Historic preservation and cultural resources

National Historic 

Preservation Act (NHPA), 

16 U.S.C. § 470 et seq.

The National Historic Preservation Act (NHPA) was enacted to create a 

national historic preservation program, including the National Register of 

Historic Places and the Advisory Council on Historic Preservation. 

Section 106 of the Act requires Federal agencies to take into account the 

effects of their undertakings on historic properties. The Advisory Council 

on Historic Preservation regulations implementing Section 106 of the Act 

are found in 36 CFR Part 800. The regulations call for public involvement 

in the Section 106 consultation process, including Indian Tribes and other 

interested members of the public, as applicable.

1 B.2. Operating Permits and Other Requirements

2 Table B–2 lists the permits and licenses issued by Federal, state, and local authorities for 

3 activities at Byron.
Appendix B

B-8 

1 Table B–2. Licenses and Permits

Permit Number Dates Responsible Agency

Operating license NPF-37 Issued: 02/14/1985

Expires: 10/31/2024 NRC

Operating license NPF-66 Issued: 01/30/1987

Expires: 11/06/2026 NRC

National Pollutant Discharge 

Elimination System (NPDES) 

Permit

IL0048313 Issued: 01/24/2011

Expires: 12/31/2015

IEPA Division of Water 

Pollution Control

Water Pollution Control 

Permit 2011-EP-1250 Issued: 02/16/2011Expires: 01/31/2016

IEPA Division of Water

Pollution Control

Hazardous Materials 

Certificate of Registration 051713550083VX Issued: 05/17/2013Expires: 06/30/2016

U.S. Department of 

Transportation, Pipeline 

and Hazardous Materials 

Safety Administration

Federally Enforceable State 

Operating Permit (FESOP) 

Application

#78090018

9/11/2007;

supplemented

12/10/2007

ID# 141820AA

Issued: 12/01/2001

Expires: 12/13/2007(a)

IEPA Division of Air

Pollution Control

Notification of Hazardous 

Waste Activity ILD000806521 Not Applicable IEPA Bureau of Land

Land application of sludge 2009-SC-2169-1 Issued: 04/20/2010

Expires: 05/31/2014(b) IEPA Bureau of Land

Waste tracking permit IL-0105 Not Applicable IEMA, Division of Nuclear 

Safety

License to deliver radioactive 

material T-IL007-L12 Renewed annually

Tennessee Department 

of Environment and

Conservation

Permit to deliver radioactive 

material 0110000032 Renewed annually Utah Department of Environmental Quality

(a) 415 Illinois Compiled Statutes 5/-, Title X, Permits, Sec. 39(x) establishes the timing for submitting a permit 

renewal. Specifically, as long as the renewal is submitted before the permit is expired, the current terms and 

conditions of the permit are extended until the final administrative action has been taken on the application for the 

renewal of the permit. Because Exelon Generation met this requirement, the permit is administratively extended 

(415 ILCS 5/39(x)). 

(b) The applicant is evaluating future land applications of the river sediment. A permit renewal application will be filed 

after the evaluation is completed.

Source: Exelon 2014
Appendix B

B-9 

1 B.3. References

2 10 CFR Part 50. Code of Federal Regulations, Title 10, Energy, Part 50, “Domestic licensing of 

3 production and utilization facilities.”

4 10 CFR Part 51. Code of Federal Regulations, Title 10, Energy, Part 51, “Environmental 

5 protection regulations for domestic licensing and related regulatory functions.”

6 10 CFR Part 54. Code of Federal Regulations, Title 10, Energy, Part 54, “Requirements for 

7 renewal of operating licenses for nuclear power plants.”

8 40 CFR Part 122. Code of Federal Regulations, Title 40, Protection of Environment, Part 122, 

9 “EPA administered permit programs: the National Pollutant Discharge Elimination System.”

10 49 CFR Part 107. Code of Federal Regulations, Title 49, Transportation, Part 107, “Hazardous 

11 materials program procedures.”

12 49 U.S.C. 5108. United States Code. Title 49, Chapter 51, Part 5108, “Registration.”

13 [IAC] Illinois Administrative Code Title 32, Chapter II, Subchapter d, Part 609, “Access to 

14 facilities for treatment, storage, or disposal of low-level radioactive waste.”

15 [IAC] Illinois Administrative Code Title 35, Subtitle B, Chapter I, Subchapter a, Part 201, 

16 “Permits and general provisions.”

17 [IAC] Illinois Administrative Code Title 35, Subtitle C, Chapter I, Part 309, “Permits.”

18 [IAC] Illinois Administrative Code Title 35, Subtitle C, Chapter II, Part 391, “Design criteria for 

19 sludge application on land.”

20 [IAC] Illinois Administrative Code Title 35, Subtitle G, Chapter I, Subchapter c, Part 722, 

21 “Standards applicable to generators of hazardous waste.”

22 [IEMA] Illinois Emergency Protection Agency, Division of Nuclear Safety. Undated. Available 

23 at: <http://www.state.il.us/iema/dns.asp> (accessed 14 May 2014).

24 [IEPA] Illinois Environmental Protection Agency, Bureau of Water. Undated. “Water Pollution 

25 Control.” Available at: <http://www.epa.state.il.us/water/index-wpc.html> (accessed 

26 14 May 2014). 

27 415 ILCS 5/Tit. II. Illinois Compiled Statutes. Chapter 415, 5, “Environmental Protection Act,” 

28 Title II, “Air pollution.”

29 415 ILCS 5/Tit. III. Illinois Compiled Statutes. Chapter 415, 5, “Environmental Protection Act,” 

30 Title III, “Water pollution.”

31 [AEA] Atomic Energy Act of 1954, as amended. 42 U.S.C. § 2011 et seq.

32 [CAA] Clean Air Act of 1963, as amended. 42 U.S.C. § 7401 et seq.

33 [CWA] Clean Water Act of 1977, as amended. 33 U.S.C. § 1251 et seq.

34 [ESA] Endangered Species Act of 1973, as amended. 16 U.S.C. § 1531 et seq.

35 [Exelon] Exelon Generation Company. LLC. 2014. “Update to Chapter 9 of Byron and 

36 Braidwood Stations, Units 1 and 2 License Renewal Application, Byron Station Applicant’s 

37 Environmental Report.” May 12, 2014. Agencywide Documents Access and Management 

38 System No. ML14132A141.

39 [FWCA] Fish and Wildlife Coordination Act of 1934, as amended. 16 U.S.C. § 661 et seq.

40 [MMPA] Marine Mammal Protection Act of 1972, as amended. 16 U.S.C. § 1361 et seq.
Appendix B

B-10

1 [MSA] Magnuson–Stevens Fishery Conservation and Management Act, as amended. 

2 16 U.S.C. § 1801 et seq.

3 [NHPA] National Historic Preservation Act of 1966, as amended. 16 U.S.C. § 470 et seq.

4 Pollution Prevention Act of 1990. 42 U.S.C. § 13101 et seq.

5 [RCRA] Resource Conservation and Recovery Act of 1976, as amended. 42 U.S.C. § 6901 

6 et seq.

7 Wild and Scenic Rivers Act, as amended. 16 U.S.C. § 1271 et seq.
1 APPENDIX C 

2 CONSULTATION CORRESPONDENCE

C-1 

1 C. CONSULTATION CORRESPONDENCE

2 C.1. Section 7 Consultation

3 C.1.1. Federal Agency Obligations Under ESA Section 7 

4 As a Federal agency, the U.S. Nuclear Regulatory Commission (NRC) must comply with the 

5 Endangered Species Act of 1973, as amended (16 United States Code (U.S.C.) § 1531 et seq.; 

6 herein referred to as ESA), as part of any action authorized, funded, or carried out by the 

7 agency, such as the proposed agency action that this supplemental environmental impact 

8 statement (SEIS) evaluates: whether to issue renewed licenses for the continued operation of 

9 Byron Station, Units 1 and 2 (Byron), for an additional 20 years beyond the current license 

10 terms. Under section 7 of the ESA, the NRC must consult with the U.S. Fish and Wildlife 

11 Service (FWS) and the National Marine Fisheries Service (NMFS) (referred to jointly as “the 

12 Services” and individually as “Service”), as appropriate, to ensure that the proposed agency 

13 action is not likely to jeopardize the continued existence of any endangered or threatened 

14 species or result in the destruction or adverse modification of designated critical habitat. 

15 The ESA and the regulations that implement ESA section 7 (Title 50 of the Code of Federal 

16 Regulations (50 CFR) Part 402, “Interagency cooperation—Endangered Species Act of 1973, 

17 as amended”) describe the consultation process that Federal agencies must follow in support of 

18 agency actions. As part of this process, the Federal agency shall either request that the 

19 Services provide a list of any listed or proposed species or designated or proposed critical 

20 habitats that may be present in the action area or request that the Services concur with a list of 

21 species and critical habitats that the Federal agency has created (50 CFR 402.12(c)). If it is 

22 determined that any such species or critical habitats may be present, the Federal agency is to 

23 prepare a biological assessment to evaluate the potential effects of the action and determine 

24 whether the species or critical habitat are likely to be adversely affected by the action 

25 (50 CFR 402.12(a); 16 U.S.C. § 1536(c)). Furthermore, biological assessments are required for 

26 any agency action that is a “major construction activity” (50 CFR 402.12(b)), which the ESA 

27 regulations define to include major Federal actions significantly affecting the quality of the 

28 human environment under the National Environmental Policy Act of 1969, as amended 

29 (42 U.S.C. §4321 et seq.; herein referred to as NEPA) (50 CFR 402.02).

30 Federal agencies may fulfill their obligations to consult with the Services under ESA section 7 

31 and to prepare a biological assessment in conjunction with the interagency cooperation 

32 procedures required by other statutes, including NEPA (50 CFR 402.06(a)). In such cases, the 

33 Federal agency should include the results of the ESA section 7 consultation in the NEPA 

34 document (50 CFR 402.06(b)). Accordingly, Section D.1.2 describes the biological assessment 

35 prepared for the proposed agency action evaluated in this SEIS, and Section D.1.3 describes 

36 the chronology and results of the ESA section 7 consultation.

37 C.1.2. Biological Assessment

38 The NRC considers this SEIS to fulfill its obligation to prepare a biological assessment under 

39 ESA section 7. Accordingly, the NRC did not prepare a separate biological assessment for the 

40 proposed Byron license renewal.

41 Although the contents of a biological assessment are at the discretion of the Federal agency 

42 (50 CFR 402.12(f)), the ESA regulations suggest information that agencies may consider for 

43 inclusion. The NRC has considered this information in the following sections.
Appendix C

C-2 

1 Section 3.8 describes the action area and the Federally listed and proposed species and 

2 designated and proposed critical habitat that have the potential to be present in the action area. 

3 This section includes information pursuant to 50 CFR 402.12(f)(1), (2), and (3).

4 Section 4.8 provides an assessment of the potential effects of the proposed Byron license 

5 renewal on the species and critical habitat present and the NRC’s effect determinations, which 

6 are consistent with those identified in Section 3.5 of the Endangered Species Consultation 

7 Handbook (FWS and NMFS 1998). The NRC also addresses cumulative effects and 

8 alternatives to the proposed action. This section includes information pursuant to 

9 50 CFR 402.12(f)(4) and (5).

10 C.1.3. Chronology of ESA Section 7 Consultation

11 Upon receipt of Exelon’s license renewal application, the NRC staff considered whether any 

12 Federally listed or proposed species or designated or proposed critical habitats may be present 

13 in the action area (as defined at 50 CFR 402.02) for the proposed Byron license renewal. No 

14 species under the NMFS’s jurisdiction occur within the action area. Therefore, the NRC staff did 

15 not consult with the NMFS. With respect to species under the FWS’s jurisdiction, the NRC staff 

16 compiled a list of ESA-protected species and critical habitats within the vicinity of the facility and 

17 requested the FWS’s concurrence with this list in accordance with the ESA section 7 regulations 

18 at 50 CFR 402.12(c) in a letter dated August 8, 2013. The FWS concurred with the NRC staff’s

19 list in an e-mail dated August 30, 2013, and indicated that an additional species—the leafy 

20 prairie clover (Dalea foliosa)—may potentially be present in the area. The NRC used this 

21 correspondence as a starting point for its analysis of effects to Federally listed species, which 

22 appears in Sections 3.8 and 4.7 of this SEIS. In Section 3.8, the NRC staff concludes that no 

23 ESA-protected species or critical habitats occur in the action area, and Section 4.7 concludes 

24 that the proposed action would have no effect on any ESA-protected species or critical habitats. 

25 The FWS (2013) does not typically provide its concurrence with “no effect” determinations by 

26 Federal agencies. Thus, the ESA does not require further informal consultation or the initiation 

27 of formal consultation with the FWS for the proposed Byron license renewal. Nonetheless, 

28 because this SEIS constitutes the NRC’s biological assessment, the NRC staff will submit a 

29 copy of this SEIS, upon its issuance, to the FWS for review in accordance with 

30 50 CFR 402.12(j).

31 Table C–1 lists the letters, e-mails, and other correspondence related to the NRC’s ESA

32 obligations with respect to its review of the Byron license renewal application. This table will be 

33 updated in the final SEIS, as applicable, to include correspondence transpiring between the 

34 issuance of the draft and final SEIS.
Appendix C

C-3 

1 Table C–1. Section 7 Consultation Correspondence

Date Sender and 

Recipient Description

ADAMS 

Accession 

No.(a)

August 8, 2013 M. Wong (NRC)

to T. Melius (FWS)

Request for concurrence with list of 

Federally listed species and habitats for 

the proposed Byron license renewal

ML13176A377

August 30, 2013 J. Duyvejonck (FWS)

to B. Grange (NRC)

Response to request for concurrence with 

list of Federally listed species and habitats ML13246A385

September 3, 2013

B. Grange (NRC)

to J. Duyvejonck 

(FWS)

RE: Response to request for concurrence 

with list of Federally listed species and 

habitats

ML13246A386

(a) These documents can be accessed through the NRC’s Agencywide Documents Access and Management 

System (ADAMS) at the following URL: http://adams.nrc.gov/wba/. 

2 C.2. Essential Fish Habitat Consultation

3 The NRC must comply with the Magnuson–Stevens Fishery Conservation and Management 

4 Act, as amended (16 U.S.C. §1801 et seq., herein referred to as MSA), for any actions 

5 authorized, funded, or undertaken, or proposed to be authorized, funded, or undertaken that 

6 may adversely affect any essential fish habitat (EFH) identified under the MSA.

7 In Sections 3.8 and 4.8 of this SEIS, the NRC staff concludes that the NMFS has not designated 

8 EFH under the MSA in the Rock River and that the proposed Byron license renewal would have 

9 no effect on EFH. Thus, the MSA does not require the NRC to consult with the NMFS for the 

10 proposed Byron license renewal.

11 C.3. Section 106 Consultation

12 The National Historic Preservation Act (NHPA) requires Federal agencies to consider the effects 

13 of their undertakings on historic properties and consult with applicable state and Federal 

14 agencies, tribal groups, and individuals and organizations with a demonstrated interest in the 

15 undertaking before taking action. Historic properties are defined as resources that are eligible 

16 for listing on the National Register of Historic Places. The historic preservation review process 

17 (16 U.S.C. § 470f) is outlined in regulations issued by the Advisory Council on Historic 

18 Preservation (ACHP) in 36 CFR Part 800. In accordance with 36 CFR 800.8(c), the NRC has 

19 elected to use the NEPA process to comply with its obligations under Section 106 of the NHPA.

20 Table C–2 lists the chronology of consultation and consultation documents related to the NRC 

21 Section 106 review of the Byron license renewal. The NRC staff is required to consult with the 

22 noted agencies and organizations in accordance with the statutes listed above.
Appendix C

C-4 

1 Table C–2. NHPA Correspondence

Date Sender and 

Recipient Description ADAMS Accession No. (a)

August 9, 2013

M. Wong (NRC) to 

A. Haaker, Illinois 

Historic 

Preservation 

Agency

Request for scoping

comments/notification of Section 106 

review

ML13190A331

August 9, 2013 M. Wong (NRC) to 

R. Nelson (ACHP)

Request for scoping

comments/notification of Section 106 

review

ML13184A052

August 9, 2013

M. Wong (NRC) to 

J. Greendeer, 

Ho-Chunk Nation

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

August 9, 2013

M. Wong (NRC) to 

D. Lankford, Miami 

Tribe of Oklahoma

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

August 9, 2013

M. Wong (NRC) to 

J. Froman, Peoria 

Tribe of Indians of 

Oklahoma

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

August 9, 2013

M. Wong (NRC) to 

J. Barrett, 

Chairman, Citizen 

Potawatomi Nation

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

August 9, 2013

M. Wong (NRC) to 

A. Sanache, 

Chairman, Sac and 

Fox Tribe of the 

Mississippi in 

lowa/Meskwaki

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

August 9, 2013

M. Wong (NRC) to 

M. Dougherty, 

Chairman, Sac and 

Fox Nation of 

Missouri in Kansas 

and Nebraska

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

August 9, 2013

M. Wong (NRC) to 

G. Thurman, 

Principal, Sac and 

Fox Nation

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

August 9, 2013

M. Wong (NRC) to 

M. Wesaw, 

Chairman, Pokagon 

Band of 

Potawatomi

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127
Appendix C

C-5 

Date Sender and 

Recipient Description ADAMS Accession No. (a)

August 9, 2013

M. Wong (NRC) to 

H. Frank, 

Chairman, Forest 

County Potawatomi

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

August 9, 2013

M. Wong (NRC) to 

K. Meshigaud, 

Tribal Chairman, 

Hannahville Indian 

Community, Band 

of Potawatomi

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

August 9, 2013

M. Wong (NRC) to 

S. Ortiz, Chairman, 

Prairie Band of 

Potawatomi Nation

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

August 9, 2013

M. Wong (NRC) to 

J. Blackhawk, 

Chairman, 

Winnebago Tribe of 

Nebraska

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

August 9, 2013

M. Wong (NRC) to 

S. Cadue, 

Chairman, 

Kickapoo Tribe in 

Kansas

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

August 9, 2013

M. Wong (NRC) to 

G. Salazar, 

Chairman, 

Kickapoo Tribe of 

Oklahoma

Request for scoping comments 

concerning the Byron Nuclear Generating 

Station, Units 1 and 2, LRA Review 

(notification of Section 106 review)

ML13184A127

September 4, 2013

A. Haaker, Illinois

Historic 

Preservation 

Agency to 

C. Bladey (NRC)

Illinois Historic Preservation Agency

Documentation of No Historic Sites 

Affected by Byron License Renewal 

Application

ML13269A020

(a)These documents can be accessed through the NRC’s Agencywide Documents Access and Management System 

(ADAMS) at http://adams.nrc.gov/wba/. 

1 C.4. References

2 36 CFR Part 800. Code of Federal Regulations, Title 36, Parks, Forests, and Public Property, 

3 Part 800, “Protection of historic properties.”

4 50 CFR Part 402. Code of Federal Regulations, Title 50, Wildlife and Fisheries, Part 402, 

5 “Interagency cooperation—Endangered Species Act of 1973, as amended.”

6 [ESA] Endangered Species Act of 1973, as amended. 16 U.S.C. §1531 et seq. 
Appendix C

C-6 

1 [FWS] U.S. Fish and Wildlife Service. 2013. “Endangered Species Program: What We Do: 

2 Consultations: Frequently Asked Questions.” July 15, 2013. Available at 

3 <http://www.fws.gov/endangered/what-we-do/faq.html#8> (accessed 5 June 2014).

4 [FWS and NMFS] U.S. Fish and Wildlife Service and National Marine Fisheries Service. 1998. 

5 Endangered Species Consultation Handbook: Procedures for Conducting Consultation and 

6 Conference Activities Under Section 7 of the Endangered Species Act. March 1998. 315 p. 

7 Available at <http://www.fws.gov/endangered/esa-library/pdf/esa_section7_handbook.pdf> 

8 (accessed 8 July 2013).

9 [MSA] Magnuson–Stevens Fishery Conservation and Management Act, as amended. 

10 16 U.S.C. § 1801 et seq. 

11 [NEPA] National Environmental Policy Act of 1969, as amended. 42 U.S.C. §4321 et seq. 

12 [NHPA] National Historic Preservation Act of 1966, as amended. 16 U.S.C. §470 et seq.
1 APPENDIX D 

2 CHRONOLOGY OF ENVIRONMENTAL REVIEW CORRESPONDENCE

D-1 

1 D. CHRONOLOGY OF ENVIRONMENTAL REVIEW 

2 CORRESPONDENCE

3 This appendix, along with Appendix D, contains a chronological listing of correspondence 

4 between the U.S. Nuclear Regulatory Commission (NRC) and external parties as part of its 

5 environmental review for Byron Station, Units 1 and 2 (Byron). Appendix D contains the 

6 chronological listing of consultation correspondence associated with the Endangered Species 

7 Act of 1973 (16 U.S.C. § 1531) and the Magnuson–Stevens Fishery Conservation and 

8 Management Act, as amended, (16 U.S.C. § 1801–1884). Appendix C contains all other 

9 correspondence. 

10 All documents, with the exception of those containing proprietary information, are available 

11 electronically in the NRC’s Library, which is found on the Internet at the following Web address: 

12 http://www.nrc.gov/reading-rm.html. From this site, the public can gain access to the NRC’s 

13 Agencywide Documents Access and Management System (ADAMS), which provides text and 

14 image files of the NRC’s public documents. The ADAMS number for each document is included 

15 in the following list. If you need assistance in accessing or searching in ADAMS, contact the 

16 Public Document Room Staff at 1-800-397-4209.

17 D.1. Environmental Review Correspondence

18 Table D–1 lists the environmental review correspondence in date order beginning with the 

19 request by Exelon Generation Company, LLC (Exelon or the applicant), to renew the operating 

20 license for Byron.
Appendix D

D-2 

1 Table D–1. Environmental Review Correspondence

Date Correspondence Description ADAMS No.

29-May-13 License Renewal Application, Byron and Braidwood Stations, 

Units 1 and 2 ML131620554

31-May-13 Byron License Renewal Application Environmental Report ML14022A048

06-Jun-13

Receipt and Availability of the License Renewal Application for 

the Byron Nuclear Station, Units 1 and 2, and the Braidwood 

Nuclear Station Units 1 and 2

ML13144A099

10-Jun-13

NRC Announces Public Availability of License Renewal 

Application for Braidwood and Byron Nuclear Power Plants in 

Illinois

ML13161A381

05-Jul-13 Illinois Environmental Protection Agency, Certification Under 

Section 401 of the Clean Water Act (CWA) ML14113A544

16-Jul-13

Determination Of Acceptability And Sufficiency For Docketing, 

Proposed Review Schedule, And Opportunity For A Hearing 

Regarding The Application From Exelon Generation Company, 

LLC, For Renewal Of The Operating Licenses For Byron Nuclear 

Station, Units 1 and 2, and Braidwood Nuclear Station, Units 1 

and 2

ML13134A136

18-Jul-13

Federal Register notice (FRN) - License renewal application; 

notice of docketing and opportunity to request a hearing and to 

petition for leave to intervene

ML13134A156

24-Jul-13

Press Release-13-062: NRC Announces Hearing Opportunity on 

License Renewal Application for Byron and Braidwood Nuclear 

Plants in Illinois

ML13207A291

31-Jul-13

Byron, Notice of Intent to Prepare an Environmental Impact 

Statement and Conduct Scoping Process, Public Meetings, and 

Opportunity to Comment

ML13175A072

07-Aug-13

08/20/2013 Forthcoming Meeting to Discuss the License 

Renewal Process and Environmental Scoping for Exelon 

Generation Company, LLC (Exelon), Byron Nuclear Station, Units 

1 and 2

ML13205A045

08-Aug-13

Notice Of Intent To Prepare An Environmental Impact Statement 

And Conduct Scoping Process For License Renewal For Byron 

Station, Units 1 And 2 (TAC Nos. MF1834 And MF1835)

ML13184A110

12-Aug-13 NRC Public Meetings to Discuss Environmental Reviews of 

Byron, Braidwood Nuclear Plant License Renewals ML13224A318

27-Aug-13

Comment (2) of Kim P. Gouker on Behalf of Ogle County, Illinois, 

Supporting License Renewal Application of the Byron Power 

Generating Station

ML13247A010

04-Sep-13 Illinois Historic Preservation Agency Documentation of No 

Historic Sites Affected by Byron License Renewal Application ML13269A020

10-Sep-13 Environmental Site Audit Regarding Byron Station, Units 1 And 2 

(TAC Nos. MF1834 and MF1835) ML13231A060
Appendix D

D-3 

Date Correspondence Description ADAMS No.

16-Sep-13

Comment (1) of Kim P. Gouker on Behalf of Ogle County, Illinois, 

Supporting the License Renewal Application of the Byron Power 

Generating Station

ML13263A221

23-Sep-13 Hearing Request and Petition to Intervene by the Environmental 

Law and Policy Center ML13270A137

27-Sep-13

Comment (2) of David Kraft on Behalf of NEIS re Supplement to 

NRC’s Generic Environmental Impact Statement for License 

Renewal for the Byron Nuclear Power Station

ML13277A306

04-Oct-13

Summary of the Site Audit Related to the Review of the License 

Renewal Application for Byron Nuclear Station, Units 1 and 2 

(TAC Nos. MF1834 and MF1835)

ML13270A069

04-Oct-13

Summary of Public Scoping Meetings Conducted Related to the 

Review of the Byron Nuclear Station, License Renewal 

Application (TAC Nos. MF1790 and MF1791)

ML13240A234

04-Oct-13

Memorandum from Andrew L. Bates, Acting Secretary of the 

Commission, to E. Roy Hawkens, Chief Administrative Judge of 

the Atomic Safety and Licensing Board, Referring the hearing 

request and petition to intervene from the Environmental Law and 

Policy Center

ML13277A454

08-Oct-13 Establishment of Atomic Safety and Licensing Board ML13281A798

28-Oct-13 NRC Staff Answer to Environmental Law and Policy Center 

Hearing Request and Petition to Intervene ML13301A922

28-Oct-13 Exelon’s Answer Opposing the Hearing Request and Petition to 

Intervene Filed by the Environmental Law and Policy Center ML13301A773

29-Oct-13

License Renewal Environmental Site Audit re Byron and 

Braidwood Stations - Severe Accident Mitigation Alternative (TAC 

Nos. MF1834/1835, MF1790/1791, MF1832/1833, and 

MF1792/1793)

ML13270A116

04-Nov-13 Reply in Support of the Environmental Law and Policy Center’s 

Hearing Request and Petition to Intervene ML13308D017

19-Nov-13 Memorandum and Order (Denying Hearing Request and Petition 

to Intervene) ML13323A823

21-Nov-13

Requests For Additional Information For The Environmental 

Review Of The Byron Nuclear Station, Units 1 And 2, License 

Renewal Application

ML13294A341

13-Dec-13 Audit Trip Report SAMA ML13312A317

19-Dec-13

Byron, Units 1 and 2, Response to NRC Request for Additional 

Information, dated November 21, 2013, Related to the Byron and 

Braidwood, Units 1 and 2, License Renewal Application, Byron 

Station Applicant’s Environmental Report

ML14007A078

02-Jan-14 ELPC Reply in Support of Its Appeal of the ASLB Denial of 

ELPC’s Petition for Intervention and Hearing Request ML14002A455
Appendix D

D-4 

Date Correspondence Description ADAMS No.

06-Jan-14

Requests for Additional Information for the Review of the Byron 

and Braidwood Nuclear Stations License Renewal Application - 

Severe Accident Mitigation Alternatives Review (TAC 

Nos. MF1790, MF1791, MF1792, and MF1793)

ML13318A208

13-Jan-14 Byron Environmental RAIs - 1 supplemental request ML14013A339

23-Jan-14 Byron-Braidwood SAMA RAI Conference Call Summary ML14007A240

23-Jan-14 ELPC’s Motion for Leave to File Its Reply ML14023A884

29-Jan-14

Requests For Additional Information For The Environmental 

Review Of The Byron Nuclear Station, Units 1 And 2, License 

Renewal Application - Additional Request

ML14014A036

03-Feb-14 Exelon’s Answer Opposing ELPC’s Untimely Motion for Leave to 

File a Reply ML14034A313

03-Feb-14 NRC Staff Answer Opposing Environmental Law and Policy 

Center Motion for Leave to File Reply ML14034A406

04-Feb-14

Braidwood, Units 1 & 2, and Byron, Units 1 & 2, Response to 

NRC Requests for Additional Information for the Severe Accident 

Mitigation Alternatives Review, dated January 6, 2014, License 

Renewal Application

ML14035A512

11-Feb-14

Byron Station, Units 1 & 2, Response to NRC Request for 

Additional Information on License Renewal Application and 

Environmental Report

ML14045A101

05-May-14

Schedule Revision for Environmental Review of Byron and 

Braidwood Nuclear Stations License Renewal Application - 

Environmental Review Schedule (TAC Nos. MF1790, MF1791, 

MF1792, And MF1793).

ML14104B131

07-May-14

Commission Decision (CLI-14-06) Denying the Request for a 

Protective Stay of the Byron/Braidwood License Renewal 

Proceeding.

ML14127A220

12-May-14

Update to Chapter 9 of Byron and Braidwood Stations, Units 1 

and 2 License Renewal Application, Byron Station Applicant’s 

Environmental Report.

ML14132A141

28-May-14

Issuance Of Environmental Scoping Summary Report Associated 

With The Staff’s Review Of The Byron Nuclear Station, Units 1 

And 2, License Renewal Application.

ML14041A334

17-Oct-14

Schedule Revision for the Environmental Review of the Byron 

Station And Braidwood Station License Renewal Application— 

Environmental Review Schedule (TAC Nos. MF1790, MF1791, 

MF1792, And MF1793).

ML14275A003
1 APPENDIX E 

2 PROJECTS CONSIDERED IN THE CUMULATIVE IMPACTS ANALYSIS

E-1 

1 E. PROJECTS CONSIDERED IN THE CUMULATIVE IMPACTS 

2 ANALYSIS 

3 Table E–1 identifies actions and projects considered in the U.S. Nuclear Regulatory 

4 Commission (NRC) staff’s analysis of cumulative impacts related to the environmental analysis 

5 of the continued operation of Byron Station, Units 1 and 2 (Byron). Potential cumulative impacts 

6 associated with these actions and projects are addressed in Section 4.16 of this SEIS. 

7 However, not all actions or projects listed in this appendix are considered in each resource area 

8 because of the uniqueness of the resource and its geographic area of consideration. 
Appendix E

E-2 

1 Table E–1. Projects and Actions Considered in the Cumulative Impacts Analysis

Project Name Summary of Project Location (relative 

to Byron) Status

Nuclear projects

Quad Cities Nuclear Power 

Station, Units 1 and 2 

Nuclear power plant, 

two 867-MWe

General Electric Type 3 

reactors 

Rock Island 

County, IL, 50 mi 

(~80 km) radius 

overlaps with 

Byron

Operational

(NRC 2014a, 2014b)

Clinton Power Station, 

Unit 1 

Nuclear power plant, 

one 1,043-MWe 

General Electric Type 6 

reactor

DeWitt County, IL, 

50 mi (~80 km) 

radius overlaps 

with Byron

Operational

(NRC 2014c)

Braidwood Station, Units 1 

and 2

Nuclear power plant, 

two 1,121-MWe 

Westinghouse four-loop 

reactors

Will County, IL, 

50 mi (~80 km) 

radius overlaps

with Byron

Operational

(NRC 2014d, 2014e)

LaSalle County Station, 

Units 1 and 2

Nuclear power plant, 

two 1,200-MWe 

General Electric Type 5 

reactors

LaSalle County, IL, 

50 mi (~80 km) 

radius overlaps 

with Byron

Operational

(NRC 2014f, 2014g)

Dresden Nuclear Power 

Station, Units 2 and 3

Nuclear power plant, 

two 867-MWe 

General Electric Type 3 

reactors

Grundy County, IL, 

50 mi (~80 km) 

radius overlaps 

with Byron

Operational

(NRC 2014h, 2014i)

Dresden Nuclear Power 

Station, Unit 1 Nuclear power plant

Grundy County, IL, 

50 mi (~80 km) 

radius overlaps 

with Byron

Shut down in 

October 1978 and is 

currently in SAFSTOR. 

No dismantlement 

activities are underway. 

All spent fuel from DNPS 

Unit 1 transferred to the 

onsite Independent Spent 

Fuel Storage Installation

(NRC 2014j).

Hydroelectric project

North American Hydro 

Rockton Plant

Hydroelectric power plant 

located on the Rock River; 

two units totaling 

1,100 kW installed 

generating capacity

Rockton, IL, 

approximately 

28 mi (~45 km) 

north

Operational

(NAH 2014)

Gas fired project

Nelson Energy Center

Combined-cycle plant with 

584 MWe generating 

capacity

Rock Falls, IL, 

approximately 

29 mi (~47 km) 

south

Under construction; 

projected to open 2015 

(Invenergy 2014)
Appendix E

E-3 

Project Name Summary of Project Location (relative 

to Byron) Status

Landfills

Rochelle Municipal Landfill 

No. 2 

Permitted landfill area of 

80.6 ac (32.6 ha) and a 

permitted disposal area of 

61.3 ac (24.8 ha); design 

capacity of 14,516,000 yd3

(11,098,000 m3)

Creston, IL, 

approximately 

19 mi (~31 km) 

southeast

Operational, NPDES

Permit No. IL0075451

(IEPA 2013)

Veolia ES Orchard Hills 

Landfill

Permitted landfill area of 

446.32 ac (180.62 ha) and 

a permitted disposal area 

of 251.1 ac (101.6 ha); 

design capacity of

45,369,400 yd3

(34,687,300 m3)

Davis Junction, IL, 

approximately 9 mi 

(~15 km) east

Operational, NPDES

Permit No. IL0075591

(IEPA 2013)

Water supply and treatment facilities

City of Byron, water supply

Withdraws groundwater

from Galesville and 

St. Simon aquifers

Byron, IL, 

approximately 3 mi 

(~5 km) northeast

Operational (EPA 2014c)

City of Byron, wastewater

plant

Sewage treatment facility 

on the Rock River

Byron, IL, 

approximately 3 mi 

(~5 km) northeast

Operational, NPDES

Permit No. IL0027804 

(EPA 2014a)

City of Oregon, water 

supply Withdraws groundwater

Oregon, IL, 

approximately 5 mi 

(~8 km) northeast

Operational (EPA 2014b)

Rock River Water 

Reclamation District

Water treatment plant with 

discharge to Rock River

Rockford, IL, 

approximately 

16 mi (~26 km) 

northeast

Operational, NPDES

Permit No. IL0027201

(EPA 2014a)

City of Oregon, municipal 

wastewater treatment 

facilities

Sewage treatment facility 

on the Rock River

Oregon, IL, 

approximately 5 mi 

(~8 km) northeast

Operational, NPDES

Permit No. IL0020184

(EPA 2014a)

Various minor NPDES

wastewater discharges

Various businesses with 

smaller wastewater

dischargers to water

bodies

Within 50 mi 

(~80 km) Operational (EPA 2014a)
Appendix E

E-4 

Project Name Summary of Project Location (relative 

to Byron) Status

Transportation

Jane Addams Memorial 

Tollway (I-90)

Major projects include 

completion of a new 

interchange at Illinois 

Route 47. Rebuilding and 

widening of the eastbound 

lanes between Rockford 

and Elgin, including work 

on mainline bridges and 

nine local crossroad 

bridges and ramp 

reconstruction at the 

Business 

U.S. Route 20/State Street 

Interchange in Rockford

Within 35 mi

(~56 km)

In progress by Illinois 

Department of 

Transportation; expected 

to finish in 2016 (Illinois 

Tollway 2014)

Parks and recreation sites

Franklin Creek State 

Natural Area

356 ha (~880 ac) near 

Franklin Grove, IL, with 

natural springs, hardwood 

forests, bedrock 

outcroppings, and a large 

variety of flora and fauna 

for various recreational 

activities

Approximately 

15 mi (~24 km) 

south

Operational; managed by 

Illinois Department of 

Natural Resources

(IDNR 2014a)

Castle Rock State Park

809 ha (~2,000 ac) on the 

west bank of the Rock 

River in Ogle County; 

hiking, fishing, camping, 

and small-game hunting 

occur within the park

Approximately 9 mi 

(~14 km)

southwest

Operational; managed by 

Illinois Department of 

Natural Resources

(IDNR 2014b)

Lowden State Park

95 ha (~235 ac) along the 

Rock River in Ogle 

County; hiking, fishing, 

and camping occur within 

the park

Approximately 4 mi 

(~6 km) southwest

Operational; managed by 

Illinois Department of 

Natural Resources

(IDNR 2014c)

White Pines Forest State 

Park

155 ha (~383 ac) in the 

Rock River Valley; hiking, 

fishing, and camping 

occur within the park

Approximately 

11 mi (~18 km) 

west

Operational; managed by 

Illinois Department of 

Natural Resources

(IDNR 2014d)

Recreational Areas

Various parks, boat 

launches, campgrounds, 

and swimming areas on 

the Rock River

Within 50 mi

(~80 km) Operational
Appendix E

E-5 

Project Name Summary of Project Location (relative 

to Byron) Status

Byron projects

Unit 2 steam generator 

replacement

Assumed to occur during 

normal refueling outage; 

500 additional workers 

specific to replacement; all 

work to occur on 

previously disturbed land 

on site

Byron site

Assumed to occur prior to 

the end of the 40-year 

initial license term 

(Exelon 2013)

Units 1 and 2 reactor

pressure vessel head 

replacement

Would occur during a 

7-day period; 

340 additional workers 

specific to replacement; all 

work and storage of 

reactor pressure vessel 

heads to occur on 

previously disturbed land

Byron site Assumed to occur during 

license term (Exelon 2013)

Other projects

Future Urbanization

Construction of housing 

units and associated 

commercial buildings; 

roads, bridges, and rail; 

water or wastewater

treatment or both; and 

distribution facilities and 

associated pipelines as 

described in local land-use 

planning documents

Throughout region

Construction would occur 

in the future as described 

in State and local land-use 

planning documents

Sources: EPA 2014a, 2014b, 2014c; Exelon 2013; IDNR 2014a, 2014b, 2014c, 2014d; IEPA 2013; Illinois 

Tollway 2014; Invenergy 2014; NAH 2014; NRC 2014a, 2014b, 2014c, 2014d, 2014e, 2014f, 2014g, 2014h, 2014i, 

2014j

1 E.1 References

2 [EPA] U.S. Environmental Protection Agency. 2014a. “Envirofacts search results: Facilities with 

3 permits and discharges to waters of the United States.” March 18, 2014. Available at 

4 <http://www.epa.gov/enviro/index.html> (accessed June 2014).

5 [EPA] U.S. Environmental Protection Agency. 2014b. “Envirofacts: SDWIS Search: Safe 

6 Drinking Water Search for the State of Illinois – Oregon.” June 12, 2014. Available at 

7 <http://oaspub.epa.gov/enviro/sdw_form_v2.create_page?state_abbr=IL> (accessed 

8 June 2014).

9 [EPA] U.S. Environmental Protection Agency. 2014c. “Envirofacts: SDWIS Search: Safe 

10 Drinking Water Search for the State of Illinois – Byron.” June 12, 2014. Available at 

11 <http://oaspub.epa.gov/enviro/sdw_form_v2.create_page?state_abbr=IL> (accessed 

12 June 2014).
Appendix E

E-6 

1 [Exelon] Exelon Generation Company, LLC. 2013. Appendix E – Applicant’s Environmental 

2 Report – Operating License Renewal Stage, Byron Station, Units 1 and 2, Facility Operating 

3 License Nos. NPF-37 and NPF-66. Byron, IL: Exelon. May 2013. 707 p. ADAMS 

4 No. ML14022A048.

5 [IDNR] Illinois Department of Natural Resources. 2014a. “Franklin Creek State Natural Area.” 

6 Available at <http://dnr.state.il.us/lands/landmgt/parks/r1/franklin.htm> (accessed June 2014).

7 [IDNR] Illinois Department of Natural Resources. 2014b. “Castle Rock State Park.” Available at 

8 <https://dnr.state.il.us/lands/landmgt/parks/r1/castle.htm> (accessed June 2014).

9 [IDNR] Illinois Department of Natural Resources. 2014c. “Lowden State Park.” Available at 

10 <https://dnr.state.il.us/lands/landmgt/parks/r1/lowdensp.htm> (accessed June 2014).

11 [IDNR] Illinois Department of Natural Resources. 2014d. “White Pines Forest State Park.” 

12 Available at <https://dnr.state.il.us/lands/landmgt/parks/r1/whitepns.htm> (accessed June 2014).

13 [IEPA] Illinois Environmental Protection Agency. 2013. Nonhazardous Solid Waste Management 

14 and Landfill Capacity in Illinois: 2012. Springfield, IL: IEPA. October 2013. 67 p. Available at 

15 <http://www.epa.state.il.us/land/landfill-capacity/2012/report.pdf> (accessed June 2014).

16 Illinois Tollway. 2014. “Jane Addams Memorial Tollway (I-90).” Available at 

17 <http://www.illinoistollway.com/construction-and-planning/projects-by-roadway/

18 jane-addams-memorial-tollway-i-90> (accessed June 2014).

19 [Invenergy] Invenergy, LLC. 2014. “Projects by Country: United States: Nelson.” Available at 

20 <http://www.invenergyllc.com/ProjectsbyCountry/UnitedStates/Nelson.aspx> (accessed 

21 June 2014).

22 [NAH] North American Hydro. 2014. Rockton FERC Project # 2373. 1 p. Available at 

23 <http://www.nahydro.com/sites/default/files/nahydro/documents/plants/

24 RKTN%20Data%20Sheet.pdf> (accessed June 2014).

25 [NRC] U.S. Nuclear Regulatory Commission. 2014a. “Quad Cities Nuclear Power Station, 

26 Unit 1.” April 23, 2014. Available at <http://www.nrc.gov/info-finder/reactor/quad1.html> 

27 (accessed June 2014).

28 [NRC] U.S. Nuclear Regulatory Commission. 2014b. “Quad Cities Nuclear Power Station, 

29 Unit 2.” April 23, 2014. Available at <http://www.nrc.gov/info-finder/reactor/quad2.html> 

30 (accessed June 2014).

31 [NRC] U.S. Nuclear Regulatory Commission. 2014c. “Clinton Power Station, Unit 1.” 

32 May 8, 2014. Available at <http://www.nrc.gov/info-finder/reactor/clin.html> (accessed 

33 June 2014).

34 [NRC] U.S. Nuclear Regulatory Commission. 2014d. “Braidwood Station, Unit 1.” May 8, 2014.

35 Available at <http://www.nrc.gov/info-finder/reactor/brai1.html> (accessed June 2014).

36 [NRC] U.S. Nuclear Regulatory Commission. 2014e. “Braidwood Station, Unit 2.” May 8, 2014.

37 Available at <http://www.nrc.gov/info-finder/reactor/brai2.html> (accessed June 2014).

38 [NRC] U.S. Nuclear Regulatory Commission. 2014f. “LaSalle County Station, Unit 1.” 

39 May 8, 2014. Available at <http://www.nrc.gov/info-finder/reactor/lasa1.html> (accessed 

40 June 2014).

41 [NRC] U.S. Nuclear Regulatory Commission. 2014g. “LaSalle County Station, Unit 2.” 

42 May 8, 2014. Available at <http://www.nrc.gov/info-finder/reactor/lasa2.html> (accessed 

43 June 2014).
Appendix E

E-7 

1 [NRC] U.S. Nuclear Regulatory Commission. 2014h. “Dresden Nuclear Power Station, Unit 2.” 

2 April 23, 2014. Available at <http://www.nrc.gov/info-finder/reactor/dres2.html> (accessed 

3 June 2014).

4 [NRC] U.S. Nuclear Regulatory Commission. 2014i. “Dresden Nuclear Power Station, Unit 3.” 

5 April 23, 2014. Available at <http://www.nrc.gov/info-finder/reactor/dres3.html> (accessed 

6 June 2014).

7 [NRC] U.S. Nuclear Regulatory Commission. 2014j. “Dresden – Unit 1.” February 20, 2014.

8 Available at <http://www.nrc.gov/info-finder/decommissioning/power-reactor/ 

9 dresden-nuclear-power-station-unit-1.html> (accessed June 2014).

1 APPENDIX F 

2 U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION OF 

3 SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR BYRON 

4 STATION, UNITS 1 AND 2, IN SUPPORT OF LICENSE RENEWAL 

5 APPLICATION REVIEW

F-1 

1 F. U.S. NUCLEAR REGULATORY COMMISSION STAFF EVALUATION 

2 OF SEVERE ACCIDENT MITIGATION ALTERNATIVES FOR BYRON 

3 STATION, UNITS 1 AND 2, IN SUPPORT OF LICENSE RENEWAL 

4 APPLICATION REVIEW

5 F.1 Introduction

6 Exelon Generation Company, LLC (Exelon) submitted an assessment of severe accident

7 mitigation alternatives (SAMAs) for the Byron Station, Units 1 and 2 (Byron), as part of the 

8 Environmental Report (ER) (Exelon 2013b). This assessment is based on the most recent 

9 Byron probabilistic risk assessment (PRA) available at that time, a plant-specific offsite 

10 consequence analysis performed using the MELCOR Accident Consequence Code System 2 

11 (MACCS2) computer code, and insights from the Byron individual plant examination (IPE) 

12 (ComEd 1994) and individual plant examination of external events (IPEEE) (ComEd 1996). In 

13 identifying and evaluating potential SAMAs, Exelon considered SAMAs that addressed the 

14 major contributors to core damage frequency (CDF) and release frequency at Byron, as well as 

15 potential SAMA candidates at other operating plants that have submitted license renewal 

16 applications. Exelon initially identified 30 potential SAMAs. This list was reduced to 27 unique 

17 SAMA candidates by eliminating SAMAs that were not applicable to Byron because of design

18 differences, that have already been implemented at Byron or the intent achieved by other 

19 means, or that have excessive implementation costs. One additional candidate SAMA was also 

20 further evaluated after accounting for analysis uncertainties. Exelon assessed the costs and 

21 benefits associated with each of the 28 potential SAMAs and concluded in the ER that 18 of the 

22 candidate SAMAs evaluated are potentially cost-beneficial. Exelon submitted all 18 potentially 

23 cost-beneficial SAMAs to the Byron Plant Health Committee for further implementation 

24 consideration. 

25 Based on a review of the SAMA assessment and plant audit trip conducted November 4, 5, and 

26 6, 2013, the U.S. Nuclear Regulatory Commission (NRC) staff issued requests for additional 

27 information (RAIs) to Exelon by letter dated January 6, 2014 (NRC 2014). Key questions 

28 concerned the disposition of internal and external review comments on the PRA model, the 

29 modeling of systems shared between units, additional details on the Level 2 and 3 PRA models, 

30 the scope and status of the Byron fire PRA model, the estimated seismic CDF, the identification 

31 of candidate SAMAs, the basis for the SAMA cost estimates, and the results of the uncertainty 

32 analysis. Exelon submitted additional information by letter dated February 4, 2014 

33 (Exelon 2014). In the responses, Exelon provided a discussion of the conduct of the PRA 

34 model self-assessment and the resolution of review findings, a discussion of the modeling of 

35 shared systems and the incorporation of opposite unit equipment unavailabilities, clarification of 

36 Level 2 and 3 PRA modeling details and assumptions, further details on the Byron fire PRA, 

37 analyses of additional SAMAs, updated SAMA cost information, and revised SAMA benefit 

38 analyses to fully account for seismic events and uncertainty. Exelon’s responses addressed the 

39 NRC staff’s comments and resulted in the identification of additional potentially cost-beneficial 

40 SAMAs. 

41 As a result of NRC staff RAIs, Exelon identified two additional cost-beneficial SAMAs. Exelon 

42 plans to implement one of these SAMAs and initiated engineering and procurement activities to 

43 do so. However, Exelon determined that the other SAMA would not be cost-beneficial if another 

44 SAMA that addresses insights from the Fukushima Dai-ichi accident were implemented since it 

45 would mitigate many of the largest contributors to Byron risk.
Appendix F

F-2 

1 An assessment of SAMAs for Byron is presented below.

2 F.2 Estimate of Risk for Byron

3 Exelon’s estimates of offsite risk at Byron are summarized in Section F.2.1. The summary is 

4 followed by the NRC staff’s review of Exelon’s risk estimates in Section F.2.2.

5 F.2.1 Exelon’s Risk Estimates

6 Exelon combined two distinct analyses to form the basis for the risk estimates used in the 

7 SAMA analysis: (1) the Byron Level 1 and 2 PRA models, both new models developed since 

8 the IPE models, and (2) a supplemental analysis of offsite consequences and economic impacts 

9 (a Level 3 PRA model) developed specifically for the SAMA analysis. The SAMA analysis is 

10 based on the most recent Byron Level 1 and Level 2 PRA model available at the time of the ER, 

11 the Byron PRA (Revision BB011b1). The scope of this Byron PRA includes internal floods but 

12 does not include external events.

The Byron CDF is approximately 4.0×10−5 per year for Unit 1 and 3.8×10−5 13 per year for Unit 2 

14 (Exelon 2013b). Exelon did not explicitly include the contribution from external events within the 

15 Byron SAMA risk estimates; however, it did account for the potential risk reduction benefits 

16 associated with external events by multiplying the estimated benefits for internal events by 2.5. 

17 This is discussed further in Sections F.2.2 and F.6.2.

18 The breakdown of CDF by initiating event is provided in Table F–1. As shown in this table, 

19 events initiated by loss of essential service water (SX), loss of component cooling water (CCW), 

20 and internal flooding are the dominant contributors to the CDF for both units. Exelon identified 

that station blackout (SBO) contributes 9.9×10−7 21 per year, or 2.5 percent, for Unit 1, and 

9.6×10−7 22 per year, or 2.6 percent, for Unit 2, to the total internal events CDF while anticipated 

transients without scram (ATWS) contribute 1.4×10−7 23 per year, or approximately 0.4 percent, of 

24 the total CDF for each unit (Exelon 2014). 
Appendix F

F-3 

1 Table F–1. Byron CDF for Internal Events

Initiating Event Unit 1 CDF

(per year)

Unit 1 

Percent CDF

Contribution

Unit 2 CDF

(per year)

Unit 2 Percent 

CDF

Contribution

Loss of Essential Service Water (SX) 1.8×10−5 46 1.7×10−5 45

Loss of Component Cooling Water 

(CCW) 8.3×10−6 21 8.1×10−6 21

Internal Flooding 5.6×10−6 14 5.8×10−6 15

Loss of Auxiliary Power (AP) 2.4×10−6 6 1.8×10−6 5

Small Loss-of-Coolant Accident 

(LOCA) 1.6×10−6 4 1.5×10−6 4 

Other Initiating Events 1.6×10−6 4 1.6×10−6 4

Steam Generator Tube Rupture 

(SGTR) 1.2×10−6 3 1.5×10−6 4 

General Transient and Loss of Main 

Feedwater (LMFW) 7.9×10−7 2 6.8×10−7 2 

Total (Internal Events)(a) 4.0×10−5 100 3.8×10−5 100

(a) Column totals may be different because of rounding. 

Source: Exelon 2013b

2 The Level 2 Byron PRA model that forms the basis for the SAMA evaluation is a new model and 

3 stated to represent the current state-of-the-art (Exelon 2013b). 

4 The Level 2 model utilizes a single containment event tree (CET) to assess the accident

5 progression following a core damage event and contains both phenomenological and systemic 

6 events. The Level 1 core damage sequences are binned into plant damage states (PDSs),

7 which provide the interface between the Level 1 and Level 2 CET analysis. Each PDS bin is 

8 then entered into the CET. The CET is linked directly to the Level 1 event trees and CET nodes

9 are evaluated using supporting fault trees and logic rules.

10 The result of the Level 2 PRA is a set of 13 release or source term categories, with their 

11 respective frequency and release characteristics. The results of this analysis for Byron are 

12 provided in Table F.2-8 of the ER (Exelon 2013b). The categories were defined based on the 

13 similarity of scenario release characteristics and ultimate containment failure mode. This 

14 resulted in six release categories with large early releases (LERs), four with late releases, two 

15 with small early releases, and one for an intact containment. The frequency of each release 

16 category was obtained by summing the frequency of the individual accident progression CET 

17 endpoints binned into the release category. Source terms were developed for each of the 

18 thirteen release categories using the results of Modular Accident Analysis Program (MAAP) 

19 Version 4.0.6 computer code calculations (Exelon 2013b).

20 The offsite consequences and economic impact analyses use the MACCS2 code (Chanin and 

21 Young 1998) to determine the offsite risk impacts on the surrounding environment and public. 

22 Inputs for these analyses include plant-specific and site-specific input values for core 

23 radionuclide inventory, source term and release characteristics, site meteorological data, 

24 projected population distribution (within a 50-mi (80-km) radius) for the year 2046, emergency 

25 response evacuation modeling, and economic data. The core radionuclide inventory 
Appendix F

F-4 

1 corresponds to the end-of-cycle values for Byron operating at 3,645 megawatts thermal (MWt). 

2 The magnitude of the onsite impacts (in terms of cleanup and decontamination costs and 

3 occupational dose) is based on information provided in NUREG/BR-0184 (NRC 1997c).

4 In the ER, Exelon estimated the dose to the population within 50 mi (80 km)) of the Byron site to 

5 be approximately 0.354 person-sievert (Sv) (35.4 person-rem) per year (Exelon 2013b). In 

6 addition, Exelon estimated the annual offsite economic cost impact to be $255,000 per year. 

7 The breakdown of the total population dose and offsite economic cost by containment release 

8 mode is summarized in Table F–2. Late failures due to containment overpressure events (such 

9 as loss of containment heat removal due to loss of power or cooling water) and large early 

10 release frequency (LERF) accidents caused by unisolated interfacing-systems loss-of-coolant 

11 accident (ISLOCA) dominate the population dose risk at Byron. Late containment overpressure 

12 failures dominate the offsite economic cost impact.

13 Table F–2. Breakdown of Population Dose and Offsite Economic Cost by Containment 

Release Mode (a) 14

Containment Release Mode

Population Dose

(Person-Rem(b)

Per Year)

Percent 

Contribution

Offsite 

Economic 

Cost

($/year)

Percent 

Contribution 

Containment overpressure (late) 28.3 80 222,700 88

ISLOCA 4.42 12 11,800 5

SGTR 2.16 6 17,600 7

Containment isolation failure 0.34 <1 1660 <1

Containment intact 0.13 <1 120 <1

CFE 0.09 <1 580 <1

Basemat melt-through (late) 0.02 <1 40 <1

Total(c) 35.5 100 255,000 100

(a) Values in table derived from Table F.3-9 of the ER. (b) One person-rem = 0.01 person-Sv. 

(c) Column totals may be different because of rounding. 

Key: CFE = early containment failure; ER = Environmental Report; 

ISLOCA = interfacing-systems loss-of-coolant accident; SGTR = steam generator tube rupture; Sv = sievert

15 F.2.2 Review of Exelon’s Risk Estimates 

16 Exelon’s determination of offsite risk at the Byron site is based on the following major elements 

17 of analysis:

18 (1) the Level 1 risk model that supersedes the 1994/1997 IPE submittals (ComEd 1994, 

19 1997), a new interim internal fire analysis and the seismic and other external event 

20 analyses of the 1996 IPEEE submittal (ComEd 1996);

21 (2) the new Level 2 risk model; and
Appendix F

F-5 

1 (3) the MACCS2 analyses performed by Exelon to translate fission product source terms 

2 and release frequencies from the Level 2 PRA model into offsite consequence 

3 measures.

4 Each of these analyses was reviewed by the NRC staff to determine the acceptability of the 

5 Byron’s risk estimates for the SAMA analysis, as summarized below.

6 F.2.2.1 Internal Events CDF (PRA Level 1) Model

7 The NRC staff’s review of the Byron IPE is described in an NRC letter dated December 3, 1997 

8 (NRC 1997b). Based on a review of the original and modified IPE submittal, the NRC staff 

9 concluded that the Byron IPE has met the intent of generic letter (GL) 88-20 (NRC 1988). The 

10 NRC staff review concluded that, while Exelon did not provide a definition of vulnerability, 

11 Exelon identified one “potential vulnerability” and one enhancement were. These are discussed 

12 in Section F.3.2.

13 There have been numerous revisions to the Byron PRA since the original 1994 IPE submittal. 

14 A listing of the complete revision history of the Byron PRA since the original IPE submittal was 

15 provided in the ER (Exelon 2013b) and is summarized in Table F–3 below. A comparison of the 

16 internal events CDF between the 1997 modified IPE and the current PRA model indicates there 

has been essentially no change in the total CDF (from 4.0×10−5 17 per year for both units to 

4.0×10−5 per year for Unit 1 and 3.8×10−5 18 per year for Unit 2).

The CDF value from the 1997 modified IPE (4.0×10−5 19 per year) is in the middle range of the 

20 CDF values reported in the IPEs for Westinghouse four-loop plants. Figure 11.6 of 

21 NUREG-1560 shows that the IPE-based total internal events CDF for Westinghouse four-loop 

plants ranges from 2×10−6 per year to 2×10−4 22 per year, with an average CDF for the group of 

6×10−5 23 per year (NRC 1997a). It is recognized that other plants have updated the values for 

24 CDF subsequent to the IPE submittals to reflect modeling and hardware changes. The current 

internal events CDF results for Byron (4.0×10−5 per year for Unit 1 and 3.8×10−5 25 per year for 

26 Unit 2) are comparable to results for other plants of similar vintage and characteristics. 

27 The NRC staff considered the peer review performed for the Byron PRA, and the potential 

28 impact of the review findings on the SAMA evaluation. In the ER (Exelon 2013b), Exelon briefly 

29 described the results of the 1999 Westinghouse Owners Group peer review of Revision 0 of the 

30 Byron PRA. Exelon stated that the 27 significance-level A (expected impact to be significantly 

31 nonconservative) and -level B (expected impact to be nonconservative but small) facts and 

32 observations (F&Os) generated during the peer review have been closed out. The NRC staff 

33 requested that Exelon describe what is meant by “closed out,” how this is verified, and whether 

34 these F&Os were considered in the 2012 self-assessment and the corrections incorporated in 

35 the PRA used for the SAMA analysis. In response, Exelon provided a description of the 

36 process used to track and close out F&Os as well as other potential model changes. In the 

37 ongoing model update process, the model and document changes associated with each F&O, 

38 as well as the decision to not change the model or documentation, are reviewed and approved 

39 with each official model approval in accordance with Exelon procedures. The approved 

40 dispositions of all peer review F&Os were incorporated in the SAMA PRA. Exelon stated that 

41 “changes due to the peer review F&Os were fully considered as part of the 2012 self42 assessment” (Exelon 2014).

43 The NRC staff has determined that Exelon’s disposition of the peer review findings is consistent 

44 with the guidance in Nuclear Energy Institute (NEI) 05-01 (NEI 2005) and that the final 

45 resolution of the findings provides reasonable assurance of minimal impact to the results of the 

46 SAMA analysis.
Appendix F

F-6 

Table F–3. Summary of Major PRA Models and Corresponding CDF and LERF Results (a) 1 

PRA Model Summary of Significant Changes From 

Prior Model

CDF (per year) LERF (per year)

Unit 1 Unit 2 Unit 1 Unit 2

Original IPE

(4/1994) IPE Submittal 3.1×10−5(same model)

2.7×10−6

(same model)

Modified 

IPE (b)

(3/1997)

Numerous modifications based on NRC 

concerns on Byron IPE similar to those on 

other Commonwealth Edison IPEs

4.0×10−5

(same model) Not Available

Revision 0

(10/1999)

Changed PRA model from support state 

model to linked fault tree model involving 

extensive changes to all event trees and 

fault trees

Updated all data

5.0×10−5 4.9×10−5 4.5×10−6 4.4×10−6 

Revision 1

(10/2000)

The SX pump success criterion was 

changed from two pumps to one pump. 4.6×10−5 4.5×10−5 5.4×10−6 5.3×10−6

Revision 3a

(8/2001)

Revised LOOP/DLOOP Event Tree

Revised internal flooding analysis

Incorporation of plant modifications to CVCS 

pump lube oil cooler

Incorporation of plant mod that removed 

AFW pump 1B dependency on instrument air

5.5×10−5 5.5×10−5 6.2×10−6 6.1×10−6

Revision 4

(2/2002)

Significant model enhancements to the 

following systems: RPS, ESFAS, CCW, 

PORVs, AFW, and instrument power

Updated containment failure likelihood

5.3×10−5 5.2×10−5 5.4×10−6 6.2×10−6

Revision 5

(12/2002)

Changed small LOCA and transient accident

modeling

Addressed miscellaneous model issues

Incorporated updated failure and 

unavailability data, HEPs and support 

system initiating event frequencies

4.9×10−5 4.7×10−5 4.4×10−6 4.8×10−6

Revision 5B

(6/2003)

Reevaluated the plant-specific data 

Performed full convergence analysis and a 

human failure dependency analysis

Incorporated new SX success criteria 

Revised the model so that automatic 

quantification can be performed using 

ORAM-Sentinel and PSALINK program

6.2×10−5 6.1×10−5 4.7×10−6 5.5×10−6

Revision 5F

(12/2006)

Model revised to incorporate conditional 

DLOOP for most initiators 

Updated some LERF binning

Changed modeling of ESFAS testing 

Added RWST switchover channel testing 

and common cause

5.8×10−5 5.7×10−5 4.7×10−6 5.6×10−6
Appendix F

F-7 

PRA Model Summary of Significant Changes From 

Prior Model

CDF (per year) LERF (per year)

Unit 1 Unit 2 Unit 1 Unit 2

Revision 6C

(5/2008)

Extensive model update including changes 

to AFW success criteria, revisions to human 

error probability to reflect procedure changes 

and operator interviews, revised internal 

flooding analysis, updated data analysis, and 

changes to ESW and CCW modeling.

3.6×10−5 3.6×10−5 2.5×10−6 3.1×10−6

Revision 6E3

(5/2010)

Revised RCP seal LOCA model

Incorporated revised feed and bleed success 

criteria

Incorporated AFW unit crosstie modification

Revised human reliability assessment

1.7×10−5 1.7×10−5 1.1×10−6 1.4×10−6

Revision 

BB011a

(6/2012)

Updated internal flooding analysis

Incorporated new data analysis

Incorporated new human reliability 

dependency and preinitiator analysis

Removed credit for AFW unit crosstie 

modification

4.2×10−5 4.0×10−5 2.6×10−6 3.2×10−6

Revision 

BB011b

(11/2012)

Improved modeling of ESW and CCW 

systems

Incorporated new operator actions for use of 

ESW and CCW systems

4.0×10−5 3.8×10−5 2.6×10−6 3.2×10−6

Revision 

BB011b1

(12/2012)

LERF model replaced with Level 2 model 

based on methodology of WCAP-16341-P 4.0×10−5 3.8×10−5 1.1×10−6 1.0×10−6

(a)Except for Modified IPE information, information in table is based on ER Table F.2-1 with some 

intermediate models not included.

(b) Information from ComEd 1997.

KEY: AFW = auxiliary feedwater; CCW = component cooling water; CDF = core damage frequency; 

CVCS = chemical and volume control system; DLOOP = dual unit loss of offsite power; 

ER = Environmental Report; ESFAS = engineered safety features actuation system; 

ESW = emergency service water; HEP = human error probability; IPE = individual plant examination; 

LERF = large early release frequency; LOCA = loss-of-coolant accident; LOOP = loss of offsite power; 

NRC = U.S. Nuclear Regulatory Commission; PORV = power-operated relief valve; 

PRA = probabilistic risk assessment; RCP = reactor coolant pump; RPS = reactor protection system; 

RWST = refueling water storage tank; SX = essential service water; WCAP = Westinghouse 

Commercial Atomic Power

1 The NRC staff noted in an RAI that ER Table F.2-1, describing changes made to each PRA 

2 revision, states PRA Revision 5A “[r]evised the model and data to address the PRA quality

3 issues raised by CR#00142080 (1/30/03) against Rev. 5 model.” The NRC staff requested 

4 Exelon to identify the underlying quality process issues and the corrective actions taken. In 

5 response to the RAI Exelon stated:

6 The underlying process issue that allowed these technical quality issues to occur 

7 was a premature approval of the model prior to full review as required by the 

8 work process procedure. Exelon T&RM [Training and Reference Material]

9 ER-AA-600-1015, ‘FPIE [full power, internal event] PRA Model Update,’ provides 
Appendix F

F-8 

1 specific process and review criteria for a new model to be officially approved. 

2 [Exelon 2014]

3 Exelon further stated:

4 This process was not followed adequately for Revision 5, resulting in the CR

5 [condition report]. To help ensure that the review items are performed prior to 

6 model approval, the Quantification Notebook for each official model of record 

7 (including the current model of record) now includes confirmation that the reviews 

8 required by ER-AA-600-1015 were performed to check for these and other 

9 quality issues. The Quantification Notebook documenting the listed reviews is 

10 internally independently reviewed. Signatures of the author, reviewers, and 

11 approver confirm this review has been performed, and approval of the 

12 Quantification Notebook signifies official approval of the updated model. 

13 [Exelon 2014]

14 Exelon indicated that there had been several self-assessments of the Byron PRA, with the latest 

15 in 2012 of Revision BB011a, against the Capability Category II requirements of the 2009 

16 revision of the American Society of Mechanical Engineers (ASME) PRA standard (ASME and 

17 ANS 2009). In response to an NRC staff RAI concerning this self-assessment, Exelon indicated 

18 that the self-assessment considered the guidance in Regulatory Guide 1.200, Rev. 2 

19 (NRC 2009), and was performed consistent with the NEI 00-02 (NEI 2006) self-assessment 

20 process (Exelon 2014). 

21 This self-assessment identified two supporting requirements (SRs) that were classified as not 

22 being met and 22 that were considered to meet only the Capability Category I requirements. 

23 The ER provided a tabulation of the issues related to the SRs that did not meet Capability 

24 Category II and the potential impact on the SAMA analysis. All but four of the SRs not meeting 

25 Capability Category II were associated with requirements for the LER analysis. This was a 

26 result of the self-assessment being performed on the BB011a LERF-only model. These LER 

27 issues were addressed in a subsequent assessment as discussed in Section F.2.2.3 below. For 

28 the four non-LER issues identified in the self-assessment, Exelon concluded that not meeting 

29 the Capability Category II is either conservative or is a small contributor to plant risk and, 

30 therefore, requirements would have no meaningful impact on the SAMA analysis. Based on this 

31 assessment by Exelon, the NRC staff concludes that meeting the Capability Category I 

32 requirements is reasonable for the SAMA evaluation.

33 The NRC staff noted in an RAI that the list of CDF contribution by initiating event (see Table F–1 

34 above) included a contribution due to a loss of AP but did not explicitly include a contribution 

35 due to a loss of offsite power (LOOP) (NRC 2014). Exelon indicated that the loss of auxiliary 

36 power (AP) is a loss of an internal AP bus and is modeled the same as the loss of any other 

37 support system. The LOOP contribution is included in the “Other” category and is 1.3 percent 

38 and 0.9 percent of the total internal events CDF for Units 1 and 2, respectively. These values 

39 are for the LOOP initiating event only and do not include the contributions from LOOP that are 

40 the consequences of other initiating events. Both single-unit LOOP and dual unit loss of offsite 

41 power (DLOOP) events are included in the Byron PRA (Exelon 2014).

42 The freeze date for the inclusion of plant-specific data for the model was December 2010. In 

43 response to an NRC staff RAI concerning actual or planned changes to Byron hardware or 

44 operation since the freeze date, Exelon listed a number of modifications being considered, all of 

45 which were considered as SAMAs in the license renewal analysis. In addition Exelon stated 

46 that “no potential changes in fuel cycle or fuel management are known that would affect the 

47 SAMA analysis” (Exelon 2014). 
Appendix F

F-9 

1 As indicated at the November 2013 audit and stated in an RAI response (Exelon 2014), Exelon 

2 is planning to install no-leakage reactor coolant pump (RCP) seals at Byron. This planned 

3 change is not included in the baseline SAMA analysis but is evaluated as a candidate SAMA.

4 In response to an NRC staff RAI to identify the systems that are shared or can be crosstied 

5 between units and describe the modeling, including the treatment of unavailability during 

6 outages of the other unit, Exelon indicated that the service water (SW), CCW, auxiliary 

7 feedwater (AFW), auxiliary electric power, DC power and instrument air/service air systems are 

8 shared or could be crosstied between Byron units and stated that: 

9 The Byron PRA is a fully integrated two-unit model, so all components from each

10 unit and those shared between units are explicitly modeled. Unit-specific 

11 components which can be used by the opposite unit are linked into the opposite 

12 unit’s fault tree logic structure.

13 Further, it is indicated that unavailability is modeled with both normal maintenance terms as well 

14 as outage maintenance terms for all shared components except those needed during normal full 

15 power and outage operations. The normal unavailability is based on unavailable hours during 

16 normal power operation while the outage unavailability is based on unavailable hours during an 

17 outage and total time (Exelon 2014).

18 During the concurrent reviews of the Byron ER SAMA analysis and that from the very similar 

19 Braidwood Station (Exelon 2013a), the NRC staff noted some differences in PRA results 

20 between the two sites. In an RAI, the NRC staff asked Exelon to explain the reasons for these 

21 differences, and whether the reasons suggest design or operating changes that might be cost22 beneficial for one site or the other (NRC 2014). For sequences resulting from RCP seal LOCAs 

23 following loss of CCW with failure to establish emergency core cooling system (ECCS) 

24 recirculation cooling but with successful cooldown and depressurization, for which the Byron 

25 CDF is considerably larger than that for Braidwood, Exelon indicated that the difference is due 

26 to a different normal valve alignment at Byron which requires additional operator actions (Exelon 

27 2014). For sequences resulting from random nonisolable small LOCAs with failure to establish

28 ECCS recirculation cooling but with successful cooldown and depressurization, for which the 

29 Braidwood CDF is considerably larger than that for Byron, Exelon indicated that the difference is 

30 primarily because at Braidwood the SX007 SW valves must be throttled open to establish an 

31 appropriate flow rate through the component cooling heat exchangers (HXs). This requirement 

32 results from SW’s being taken from Lake Michigan whose water temperature varies throughout 

33 the year. At Byron, the SX007 valves do not need manipulation during an accident

34 (Exelon 2014). The potential for SAMAs suggested by these differences is discussed in 

35 Section F.3.2.

36 The NRC staff concludes that the internal events Level 1 PRA model is of sufficient quality to 

37 support the SAMA evaluation based on the following:

38 • An early revision of the Byron internal events PRA model was peer-reviewed. 

39 • A more recent revision was subjected to a self-assessment using the 2009 revision of 

40 the ASME PRA standard and the guidance in Regulatory Guide 1.200, Revision 2. The 

41 self-assessment was performed consistent with the NEI 00-02 self-assessment process, 

42 and the review findings were adequately resolved. 

43 • Exelon has satisfactorily addressed NRC staff questions regarding the PRA. 

44 F.2.2.2 External Events

45 As indicated above, the Byron PRA used for the SAMA analysis does not include external 

46 events. In the absence of such an analysis, Exelon used the Byron IPEEE and other analyses 
Appendix F

F-10

1 to identify the highest risk accident sequences, to identify the potential means of reducing the 

2 risk posed by those sequences, and to estimate the benefit of potential SAMAs. This is 

3 discussed below and in Section F.3.2.

4 The Byron IPEEE was submitted in December 1996 (ComEd 1996), in response to 

5 Supplement 4 of GL 88-20 (NRC 1991). The submittal included a seismic margin assessment 

6 (SMA), a fire assessment using the Electric Power Research Institute (EPRI) fire-induced 

7 vulnerability evaluation (FIVE) guidance (EPRI 1992), and a screening analysis for other (high 

8 winds, floods and other (HFO)) external events. ComEd did not identify any vulnerabilities in 

9 the seismic, fire, or HFO areas. However, during ComEd’s IPEEE development several seismic 

10 issues were identified as “outliers.” Outliers are plant equipment or component conditions that 

11 did not meet one or more of the seismic screening criteria and, therefore, required further 

12 evaluation during the IPEEE. These outliers were considered in the SAMA evaluation, as 

13 discussed further below. In its IPEEE safety evaluation report (SER) (NRC 2001), the NRC staff 

14 concluded that the applicant’s IPEEE process is capable of identifying the most likely severe 

15 accidents and severe accident vulnerabilities for external events and, therefore, that the Byron 

16 IPEEE has met the intent of Supplement 4 to GL 88-20.

17 The Byron IPEEE seismic analysis was a focused-scope SMA following NRC guidance (Chen 

18 et al. 1991; NRC 1991). The SMA approach is deterministic in nature and does not result in 

19 probabilistic risk information. The SMA was performed using a Safe Shutdown Equipment List 

20 (SSEL) with plant walkdowns in accordance with the guidelines and procedures documented in 

21 EPRI Report NP-6041-SL (EPRI 1991). Two success paths, each capable of mitigating the 

22 effects of a seismically induced small break LOCA, were identified based on a review of the 

23 guidance and plant documentation. The components on the SSEL were then evaluated for 

24 seismic capacity. 

25 The components and associated structures in which they are housed were evaluated based on 

26 the screening criteria of NP-6041-SL. The review of major structures was based primarily on a 

27 review of the design bases augmented by a walkdown to identify any anomalous conditions. 

28 Masonry block walls were evaluated and qualified to the seismic design basis loads in 

29 compliance with the plant’s seismic evaluation criteria. Mechanical and electrical equipment 

30 that did not meet the screening criteria were considered SMA outliers. If the equipment had 

31 anchorage that was not judged robust by the walkdown team, the high confidence in low 

32 probability of failure (HCLPF) anchorage evaluation was calculated to obtain an anchorage

33 seismic capacity.

34 A total of 116 outliers were identified (NRC 2001). The majority of the outliers involve seismic

35 interaction concerns that were resolved through some corrective actions. Others were resolved 

36 either by Conservative Deterministic Failure Margin capacity analysis to show the capacity well 

37 beyond review-level earthquake demand or by maintenance or modifications. These outliers 

38 were considered further in the Phase I SAMA identification discussed in Section F.3 below.

For the purposes of the SAMA evaluation, Exelon assumed a seismic CDF of 1×10−6 39 per year in 

40 the development of the external events multiplier (Exelon 2013b). Since the SMA approach 

41 used in the IPEEE does not involve the determination of seismic CDF and Exelon did not 

42 provide a basis for the value used, the NRC staff asked Exelon to consider the impact on the 

43 SAMA analysis if a seismic CDF from the generic issue (GI) 199 risk assessment (NRC 2010b) 

44 for the Byron site were used. Exelon indicated that, if the weakest link seismic CDF value 

(5.8×10−6 45 per year) from GI 199 were used, the external events multiplier would increase from 

46 2.5 to 2.6 and reevaluated the SAMAs using this multiplier (Exelon 2014). This is discussed in 

47 more detail below.
Appendix F

F-11

1 The Byron IPEEE included an internal fire analysis employing EPRI’s FIVE methodology 

(EPRI 1992). The NRC’s IPEEE SER for Byron reports a total fire CDF of 5.0×10−6 2 per year for 

Unit 1 and 6.1×10−6 3 per year for Unit 2 (NRC 2001). However, the IPEEE fire analysis has been 

4 superseded by the 2009 Byron fire PRA, which Exelon states to be an interim implementation of 

5 NUREG/CR-6850 (NRC 2005a), given that not all tasks identified in NUREG/CR-6850 

6 (NRC 2005a) are completely addressed or implemented in the model. The total fire CDF for 

Unit 1 was reported in the ER to be 5.39×10−5 7 per year, which is an order of magnitude greater 

8 than that reported in the IPEEE SER. The Unit 2 CDF was not reported since the Unit 2 fire 

9 model had not been developed to the same degree as the Unit 1 model (this is discussed 

10 further below). While the Byron fire PRA is a risk assessment as compared to the IPEEE fire 

11 analysis, which is a screening analysis, it was not used in the SAMA analysis to estimate the 

12 risk reduction of individual SAMAs. Rather, the Byron fire PRA was used in the SAMA analysis 

13 for determining the fire contribution to the external events multiplier, as well as for identifying 

14 potential SAMAs to mitigate the internal fire risk.

15 Exelon indicated that this was because the fire model is not fully integrated with the most recent 

16 Level 2 and 3 analyses and is also based on Revision 6C of the internal events PRA rather than 

17 the current Revision BB11b1 model used for the internal events SAMA analysis. 

18 In response to an NRC staff RAI that asked for more information on the quality and 

19 development status of the 2009 Byron fire PRA, Exelon indicated that the fire PRA development 

20 tasks do not have any specific quality assurance activities (Exelon 2014). However, internal 

21 processes are used to ensure that the tasks are being performed and reviewed by 

22 knowledgeable personnel. This is accomplished by the use of certification guides in addition to 

23 each document’s having three levels of signatures: preparer, reviewer, and approver. In 

24 addition, Exelon briefly discussed several conservatisms and nonconservatisms in the current 

25 model. The major conservatism identified is in the fire modeling task, which uses generic 

26 treatments of the zone of influence and gives no credit for fire severity. The nonconservatisms 

27 identified include not accounting for the effects of hot gas layers and the limited modeling of 

28 multiple spurious operations. The human reliability analysis (HRA) is identified as having 

29 potentially both conservative and nonconservative impacts on the results. A flowchart method is 

30 used for determining the human error probabilities (HEPs). The HEPs are generic in nature and 

31 modified based on certain parameters that may not be accurate given the actual fire. In 

32 addition, the HEPs may be higher due to the unavailability of cues to give the operators a 

33 chance to respond to the event or, in some cases, timing constraints (Exelon 2014).

34 The NRC staff notes that, while the 2009 Byron fire PRA is still under development and has not 

35 been peer reviewed, the SAMA evaluation should be performed using the best available 

36 information on risk insights. The NRC staff concludes that the use of the fire PRA model

37 provides an acceptable basis for identifying and evaluating SAMA candidates based on the 

38 following criteria:

39 • The 2009 Byron fire PRA model is a more current analysis of the fire risk at Byron than 

40 the IPEEE fire analysis and, therefore, is the best currently available fire risk information.

41 • The reported fire risk is substantially higher for the fire PRA model than that from the 

42 IPEEE.

43 • The fire PRA model is being developed in accordance with NUREG/CR-6850,. 

44 The major fire core damage contributors for each unit (defined as having a CDF greater than

1×10−6 45 per year) are listed in Table F–4. This information was used by Exelon to identify 

46 potential SAMAs for the fire events and to evaluate the benefit of any SAMA uniquely directed at 

47 reducing the fire risk. This is discussed in Sections F.3 and F.4 below.
Appendix F

F-12

1 Table F–4(a). Major Byron Unit 1 Contributors to Fire CDF

Fire Zone Fire Zone Description CDF

(per year)

11.3-0 Auxiliary building general area, Elv. 364 1.4×10−5

11.6-0 Auxiliary building general area, Elv. 426 6.0×10−6

5.2-1 Div. 11 ESF switchgear room 4.2×10−6

11.3-1 Unit 1 containment pipe penetration area 4.0×10−6

11.4-0 Auxiliary building general area, Elv. 383 3.8×10−6

11.4C-0 Radwaste and remote shutdown panel control room 3.6×10−6

11.6C-0 Auxiliary building laundry room 1.8×10−6

17.2-2 SX cooling tower, div. 11/21 1.6×10−6

18.14A-1 SX tower electrical equipment room, div. 12 1.5×10−6

5.1-1 Div. 12 ESF switchgear room 1.3×10−6

3.4A-1 Unit 1 cable riser area, Elv. 451 1.2×10−6

18.3-1 Unit 1 main steam and AFW pipe tunnel 1.1×10−6

Key: AFW = auxiliary feedwater; CDF = core damage frequency; div. = Division; Elv. = Elevation; 

ESF = engineered safety feature; SX = essential service water
Appendix F

F-13

1 Table F–4(b). Major Byron Unit 2 Contributors to Fire CDF

Fire Zone Fire Zone Description CDF

(per year)

11.6-2 Div. 22 containment electrical penetrations area 2.1×10−5

11.4-0 Auxiliary building general area, Elv. 383 1.4×10−5

11.6-0 Auxiliary building general area, Elv. 426 1.1×10−5

5.2-2 Div. 21 ESF switchgear room 6.5×10−6

11.4c-0 Radwaste and remote shutdown panel control room 3.6×10−6

1-2 Unit 2 Containment 2.0×10−6

11.3f-2 SI pump 2B room 1.8×10−6

11.3g-2 Centrifugal charging pump 2B room 1.8×10−6

18.14A-1 Fuel handling building 1.8×10−6

17.2-2 SX Cooling Tower, Div. 11/21 1.7×10−6

11.3a-2 SI pump 2A room 1.7×10−6

5.1-2 Div. 22 ESF switchgear room 1.6×10−6

5.5-2 Unit 2 auxiliary electric equipment room 1.5×10−6

3.2-0 Auxiliary building, Elv. 439 1.2×10−6

Key: CDF = core damage frequency; div. = Division; Elv. = Elevation; ESF = engineered safety feature; SI = safety 

injection; SX = essential service water

As stated above, the total fire CDF for Unit 1 was reported in the ER to be 5.39×10−5 2 per year. 

3 The Unit 2 CDF was not reported or used since the Unit 2 fire model had not been developed to 

4 the same degree as the Unit 1 model. In response to an NRC staff RAI on the development 

5 status of the Unit 2 fire PRA model, Exelon explained that at the time the SAMA analysis was 

6 performed, the Byron fire model was in the process of being refined to remove model 

7 conservatisms, including such changes as taking credit for hot short probabilities to more 

8 accurately represent the potential for spurious operation, and refining the cable impacts based 

9 on additional circuit analysis. These refinements have been completed for the Byron Unit 1 fire 

10 PRA, but not for the Byron Unit 2 fire PRA. Based on this, and the similarities of the two units, 

11 the Unit 1 fire CDF was considered the most representative fire CDF for Byron (Exelon 2014).

12 The NRC staff notes that a SAMA evaluation should be performed using the best available risk 

13 information. Based on this, and the similarities between the two units, the NRC staff has 

determined that the fire CDF of 5.39×10−5 14 per year is appropriate for use in the SAMA analysis

15 for both Units 1 and 2. 

16 The Byron IPEEE analysis of high winds and tornadoes, external floods, and transportation and 

17 other nearby facility accidents (HFO events) followed the screening and evaluation approaches 

18 specified in Supplement 4 to GL 88-20 (NRC 1991). For these events, the IPEEE concluded 

19 that the Byron design conforms to the 1981 Standard Review Plan criteria (NRC 1981), and, 

20 therefore, the contribution to CDF from these events meets the IPEEE screening criterion of 

1×10−6 21 per year in NUREG–1407 (Chen et al. 1991). No vulnerabilities or enhancements were 

22 identified.
Appendix F

F-14

1 Based on the aforementioned results, Exelon indicated in the ER that the total external events 

CDF is approximately 5.8×10−5 per year (based on a seismic CDF of 1.0×10−6 2 per year, a fire 

CDF of 5.4×10−5 per year, a high wind CDF of 1.0×10−6 3 per year, an external flooding CDF of 

1.0×10−6 per year ,and transportation and other nearby accidents CDF of 1.0×10−6 4 per year), 

which is approximately 1.5 times the internal events CDF of 4.0×10−5 5 per year. The total CDF 

(internal and external events) is then approximately 9.8×10−5 6 per year or 2.5 times the Unit 1 

7 internal events CDF. This multiplier was used in the SAMA analysis in the ER to account for the 

8 impact of external events on the benefits determined from the internal events PRA. 

As discussed above, the GI 199 risk assessment gives a seismic CDF for Byron of 5.8×10−6 9 per 

year. Use of this value yields a total external events CDF of 6.3×10−5 10 per year and a total 

internal plus external events CDF of approximately 1.0×10−4 11 per year, which is approximately

12 2.6 times the Unit 1 internal events CDF. In response to an NRC staff RAI, Exelon stated that it 

13 used this higher multiplier in an updated cost-benefit analysis (Exelon 2014).

14 The NRC staff finds that the applicant’s conclusion concerning the contribution from seismic, 

15 fire, and HFO events to the multiplier used to represent the impact of external events is 

16 acceptable and finds that the applicant’s use of a multiplier of 2.6 reasonably accounts for 

17 external events in the SAMA evaluation. This is discussed further in Section F.6.2.

18 F.2.2.3 Level 2 Fission Product Release Analysis

19 The NRC staff reviewed the general process used by Exelon to translate the results of the 

20 Level 1 PRA into containment releases, as well as the results of the Level 2 analysis, as 

21 described in the ER and in response to NRC staff RAI (Exelon 2014). The current Level 2 

22 model is essentially a completely new model replacing the prior LERF model and developed 

23 specifically for the SAMA analysis. Exelon states that the current Byron Level 2 model is a 

24 state-of-the-art Level 2 analysis structure designed to address the Category II requirements of 

25 Regulatory Guide 1.200 (NRC 2009) and the ASME PRA Standard (ASME 2009). 

26 The Level 2 model is stated to be generally consistent with the “Simplified Level 2 Modeling 

27 Guidelines,” WCAP-16341-P (Westinghouse 2005). This WCAP provides a common, 

28 standardized method for pressurized-water reactors (PWRs) with large, dry containments to 

29 produce an analysis that generally meets Capability Category II of the ASME PRA standard. 

30 The guidance particularly addresses the latest understanding for induced SGTRs, direct 

31 containment heating, and other important Level 2 phenomena. While the WCAP is focused on 

32 modeling the LERF for the ASME standard, it includes guidance for including intact, small, and 

33 late releases to provide a more complete, though still standardized, Level 2 analysis.

34 In response to an NRC staff RAI that asked the applicant to identify areas where the Byron 

35 model differs from that in WCAP-16341-P, Exelon indicated that the differences include (Exelon 

36 2014):

37 • No credit for recovery of alternating current power or diesel generator repair 

38 after core damage is given. 

39 • Modeling of potential hot leg rupture following an induced tube rupture, such 

40 that the release to the environment is substantially reduced, based on recent 

41 research results from the State-of-the-Art Reactor Consequence Analysis 

42 project (Bixler et al. 2013).

43 • A combined CET is used rather than separate SBO and non-SBO CETs. 

44 This is a modeling choice and has no effect on the overall model since 

45 recovery of offsite power is not credited.
Appendix F

F-15

1 • Operator action is credited to maintain a sufficient water pool over the steam 

2 generator (SG) tubes to scrub releases in SGTR events. While not 

3 specifically included in the WCAP methodology, WCAP-16341-P does 

4 identify that this type of scrubbing is possible.

5 As described in Section F.2.3.1 of the ER, PDSs provide the interface between the Level 1 and 

6 Level 2 analyses. Each Level 1 accident sequence that leads to core damage consists of a 

7 unique combination of an initiating event followed by the success or failure of various plant 

8 systems (including operator actions). The Level 1 sequences that result in core damage are 

9 grouped into PDS bins. Each bin collects all of those sequences for which the progression of 

10 core damage, the release of fission products from the fuel, the status of the containment and its 

11 safeguards systems, and the potential for mitigating the potential radiological source terms are 

12 similar. 

13 The PDS bins for Byron are characterized by the status of containment bypass due to SGTR or 

14 ISLOCA, reactor coolant system pressure, and the availability of feedwater (FW) and AFW. 

15 For Byron, a single detailed CET, which contains both phenomenological and systemic events, 

16 assesses the accident progression following a core damage event and analyzes each PDS bin 

17 as a group. The Byron CET (shown in ER Figure F.2-4) is stated to be based on the CETs 

18 provided in WCAP-16341-P. While the function of the CET is essentially the same as the 

19 WCAP CETs, some changes were made to accommodate the capabilities and features of the 

20 Byron PRA model. The event tree begins with one or more core damage sequences and then 

21 asks a number of questions to determine the type of release, if any, that occurs. Each question 

22 is modeled as a top event in the event tree, and the outcome is based on previous work for 

23 Byron (including logic taken from the existing model), recent accident progression research, and 

24 the guidance provided in the WCAP.

25 The NRC staff noted in an RAI that ER Section F.2.3.2 indicated that containment failure due to 

26 direct containment heating is “0.000” and asked the applicant to clarify how this and other early 

27 containment failure (CFE) probabilities are included in the Level 2 models (NRC 2014). In 

28 response to the RAI, Exelon indicated that the 0.000 containment failure probability is not a 

29 typo, but is the value reported from WCAP-16341-P, which in turn quotes the value from 

30 NUREG/CR-6338, Resolution of Direct Containment Heating Issue for all Westinghouse Plants 

31 with Large Dry Containments or Subatmospheric Containments (Pilch et al. 1996). The WCAP 

32 notes that the NUREG provides only three significant digits. The 0.000 value applies to all 

33 sequences and all combinations of hydrogen burns, steam explosion, and direct containment 

34 heating. Therefore, the probability of CFE at Byron or Braidwood is negligible for any sequence. 

35 However, in order to maintain flexibility in the model for sensitivity analyses, the CFE probability 

36 is maintained in the model and assigned a probability of 0.001 for any cause or combination of 

37 causes (Exelon 2014).

38 Each CET end state represents a radionuclide release to the environment and is assigned to a 

39 release category. Four general release categories were defined: (1) intact, (2) late release, 

40 (3) small early release, and (4) LER. Because there are a large number of Level 2 sequences 

41 that contribute to each general release category with varying release characteristics, the general 

42 release categories are subdivided into 13 detailed release categories.

43 The LER categories are for the containment bypass or failure conditions that lead to the release: 

44 unisolated ISLOCAs, containment isolation failures, CFEs, noninduced SGTRs with and without 

45 FW, and pressure- or thermal-induced SGTRs. The late release categories are for containment 

46 overpressure failure and basemat melt-through each with or without FW. The small early 

47 release categories are for SGTRs with FW available resulting in water level above the SG 

48 tubes, and thermally induced SGTRs shortly followed by hot-leg failure.
Appendix F

F-16

1 Exelon developed the accident progression and associated release characteristics for each 

2 release category, by using the results of MAAP Version 4.0.6 computer code calculations. A 

3 representative sequence was selected for each detailed release considering both the likelihood 

4 of the scenario and its potential consequences. Since source terms are not always available for 

5 each sequence making up a release category, the selection of the representative sequences 

6 were based on judgment as to the potential consequences. Exelon stated that the sequence 

7 that is judged to be associated with a higher potential source term is used as the representative 

8 sequence unless there is another sequence that accounts for a majority of the release category 

9 frequency and the sequence with the “higher” source term accounts for less than about 

10 10 percent of the release category frequency. In those cases, the “majority” sequence would be 

11 chosen as representative (Exelon 2013b). Table F.2-6 of the ER describes the representative 

12 sequence used for each release category. Table F.3-8 of the ER describes and justifies the 

13 MAAP case for each representative sequence and provides the resulting key event timings. In 

14 response to an NRC staff RAI, Exelon stated that the input for the MAAP cases specified the 

15 fission product mass as recommended by the MAAP Users Group Bulletin, “MAAP-FLASH #68” 

16 (Exelon 2014).

17 The above listed tables indicate that for several release categories the run duration of the MAAP 

18 analysis was quite long (200, 800, and 1,600 hours). It was stated that this duration was 

19 necessary to achieve a plateau of the release fractions, with primary attention paid to cesium 

20 iodide and cesium hydroxide release fractions. In response to NRC staff RAI that asked Exelon 

21 to explain the reason for the longer duration and to identify conservatisms in the analysis, 

22 Exelon indicated that the run times for various MAAP calculations were established based on 

23 the timing for the onset of core damage, the timing for either containment failure or containment 

24 bypass, and consideration of revaporization of fission products that initially deposited within the 

25 reactor coolant system (RCS), particularly on the SG tubes which, after the SG dries out and the 

26 tube temperature increases, the deposited fission products become available for release late in 

27 the event. The run times were selected to make sure to capture this revaporization 

28 phenomenon (Exelon 2014).

29 In response to the RAI, Exelon provided plots of the cesium iodide release as a function of time 

30 for a number of release categories, which showed that in many cases a stable total release from 

31 the containment is achieved well before the end of the run. For the dominant release category 

32 (LATE-CHR-NOAFW), which contributes 50 percent of the population dose risk and 73 percent 

33 of the offsite economic cost risk (OECR) the cesium iodide reaches a stable value at 600 hours. 

34 For cesium hydroxide (which is stated by Exelon to be the primary driver for long-term dose and 

35 costs), the release is slower, and the release fraction is still increasing at a slow rate even at 

36 1,600 hours.

37 The NRC staff notes that the above cited times of 600 hours (25 days) and 1,600 hours 

38 (67 days) are longer than the time (generally assumed to be less than 100 hours) by which it 

39 might reasonably be expected that additional onsite and offsite resources would be available to 

40 mitigate the releases. This has a significant impact on the release fractions. For example, from 

41 Exelon’s RAI response (Exelon 2014), for the dominant release category, at 72 hours, or 3 

42 days, after declaration of a general emergency, the cesium iodide release fraction is 37 percent 

43 of the value used in the consequence analysis, while the cesium hydroxide release fraction is 7 

44 percent of the value used in the consequence analysis. Alternatively, if the releases were 

45 terminated at 144 hours, or 6 days, after declaration of a general emergency, the cesium iodide

46 release would be 63 percent and the cesium hydroxide release would be 16 percent of the 

47 values used in the consequence analysis for the dominant release category. Use of these lower 

48 release fractions would result in a significant reduction in both population dose risk and OECR.
Appendix F

F-17

1 In response to an NRC staff’s RAI that asked Exelon to identify the major factors that contribute 

2 to the OECR and to discuss their realism and conservatism, Exelon, in addition to discussing 

3 the conservatism involved in using the release fractions for very long run times, identified 

4 conservative modeling involving the chemical form of cesium. NUREG/CR-7110 (Bixler et al.

5 2013) indicates that only a small fraction of the cesium is in the form of cesium iodide and that 

6 the dominant chemical form will be cesium molybdate with the remaining cesium in the form of 

7 cesium hydroxide. The Byron SAMA analyses assume that the dominant cesium chemical form 

8 is cesium hydroxide. Cesium molybdate has a very low vapor pressure and would therefore be 

9 expected to remain deposited on structures (e.g., the tubes in an SG) for a longer time relative 

10 to cesium hydroxide. Exelon concluded that the result of this assumption is a conservative 

11 SAMA assessment because the release fraction for cesium molybdate would be lower than that 

12 for cesium hydroxide (Exelon 2014).

13 The NRC staff noted in an RAI that the analysis of sequences involving containment isolation 

14 failure did not allow for CFE due to such phenomenology as hydrogen explosion or direct 

15 containment heating (NRC 2014). In response to the RAI, Exelon indicated that while hydrogen 

16 explosion and direct containment heating are potential failure modes for the containment 

17 isolation failure sequences (release category LERF-CI), the probability of CFE due to these 

mechanisms is 1×10−3 18 . While the CFE cesium iodide release fraction may be about 20 times 

19 larger than the cesium iodide release fraction for containment isolation, the frequency is 

20 1,000 times less. Further, the potential contribution from the fraction of isolation failures that 

21 result in CFE represent only about 1 percent of the other CFE frequency (release category 

22 LERF-CFE). Rebinning the CFE contributions from the LERF-CI release category into the 

23 LERF-CFE release category results in no measurable change to the reported population dose

24 risk and OECR values and, therefore, would have no impact on the SAMA analysis (Exelon 

25 2014).

26 The results of the Level 2 analysis are provided in ER Tables F.2-8 (release category 

27 frequencies) and F.2-7 (timing and magnitude of release). The NRC staff noted in an RAI that, 

28 while the release category frequencies for the two units are generally very close (within about 

29 10 to15 percent of each other), for one risk important release category (late containment failure 

30 without FW (LATE-CHR-NOAFW)) the Unit 1 frequency is 20 percent more than that for Unit 2 

31 (NRC 2014). In response to the RAI Exelon explained that the difference in Unit 1 and Unit 2 

32 results for LATE-CHR-NOAFW is related to the assumed default configurations for the two 

33 units. For Unit 1, the assumed SX pump configuration models pump 1A in standby and 

34 pump 1B running. For Unit 2, the opposite configuration is modeled, with pump 2A running and 

35 pump 2B in standby. Because other pumps have the same default configurations in both units, 

36 unique train-based power failures can occur at Unit 1 that do not occur at Unit 2. This can result 

37 in slightly different sequences because of power dependency failures such as seen here. Unit 1 

38 has the higher frequency and was used for the purposes of the SAMA analysis (Exelon 2014).

39 In response to an NRC staff RAI that asked Exelon to describe the steps taken to ensure the 

40 technical adequacy of the revised Byron Level 2 PRA model, Exelon indicated, for the initial 

41 completion of the updated Level 2 model included in Revision BB011b1 of the PRA, an internal

42 review was conducted examining accident sequence modeling, fault tree modeling, and cutset 

43 reviews. The documentation of the BB011b1 model also included a self-assessment and 

44 roadmap against Capability Category II of the ASME PRA Standard. This self-assessment and 

45 roadmap concluded that all applicable LERF SRs were met at Capability Category II. The 

46 signature of the preparer and the reviewer confirm the internal review and agreement with the 

47 conclusion of the self-assessment and roadmap. The new Level 2 model replaced the 

48 simplified, and generally conservative, previous LERF model. Reductions in LERF come from 
Appendix F

F-18

1 several improvements, including credit for an operator action to keep an SG full to scrub a 

2 release from an SGTR and reduced CFE probabilities (Exelon 2014).

3 The NRC staff reviewed the Level 2 methodology and determined that Exelon satisfactorily 

4 addressed NRC staff RAIs. While the updated Level 2 model has not been peer reviewed, 

5 Exelon assessed the Level 2 model against the LERF SRs of the ASME PRA standard and 

6 determined that all applicable SRs meet the Capability Category II requirements. Therefore, the 

7 NRC staff concludes that the Level 2 PRA is of sufficient quality to support the SAMA

8 evaluation. 

9 F.2.2.4 Level 3 Offsite Consequence Analysis

10 The NRC staff reviewed the process used by Exelon to extend the containment performance 

11 (Level 2) portion of the PRA to an assessment of offsite consequences (Level 3 PRA). This 

12 included consideration of the source terms used to characterize fission product releases for the 

13 applicable containment release categories and the major input assumptions used in the offsite 

14 consequence analyses. The MACCS2 code (Version 1.13.1) was utilized to estimate offsite 

15 consequences (Chanin and Young 1998). Plant-specific input to the code includes the source 

16 terms for each source term category and the reactor core radionuclide inventory (both 

17 discussed above), site-specific meteorological data, projected population distribution within an 

18 50-mi (80-km) radius for the year 2046, emergency evacuation modeling, and economic data. 

19 As indicated in the ER, the reactor core radionuclide inventory used in the consequence 

20 analysis was based on end-of-cycle power of 3,645 MWt. The current rated power for Byron is 

21 3,586.6 MWt, and the core radionuclide inventory was based on this power (Exelon 2008). 

22 Exelon has submitted a license amendment application to the NRC requesting a measurement 

23 uncertainty recapture (MUR) power uprate from 3,586.6 MWt to 3,645 MWt (Exelon 2011). The 

24 proposed uprate power of 3,645 MWt was included in the MACCS2 analysis by scaling the base 

25 core inventory by the power uprate ratio (1.0163). This information is provided in Section 3.5 of 

26 Attachment F to the ER (Exelon 2013b). Exelon performed a sensitivity study assuming the 

27 current rated power (3,586.6 MWt). The decrease in power of −1.63 percent resulted in a 

28 decrease in both population dose risk and cost risk of 1 percent each. 

29 Exelon modeled all releases as being from midheight of the reactor containment building and 

30 at10 MW thermal content, except for intact containment (which maintained zero energy). 

31 Exelon performed sensitivity studies using zero plume energy (Exelon 2013b). With zero plume 

32 heat the dose risk increased approximately 0.2 percent and the cost risk increased 

33 approximately 3 percent. Exelon performed sensitivity studies for plume release height and 

34 deposition velocity (Exelon 2013b). Release height set to ground level resulted in a decrease in 

35 dose risk of 1 percent and a decrease in cost risk of 3 percent. Release height set to the top of 

36 containment resulted in an increase in dose risk of 1 percent and an increase in cost risk of 

37 3 percent. The deposition velocity was reduced from 0.01 to 0.005 meter per second (m/s) 

38 (0.03 to 0.016 foot per second) (a factor of 2), which resulted in a decrease in population dose 

39 risk of 8 percent and decrease in cost risk of 19 percent. In response to an NRC staff RAI, 

40 Exelon provided additional values and assumptions associated with the MACCS2 model input, 

41 including rainfall, mixing height, building wake effects, plume energy, land fraction, region index, 

42 watershed index, growing season, fraction of farmland, and shielding and protection factors 

43 (Exelon 2014). Based on the information provided, the staff concludes that the release 

44 parameters utilized follow NRC guidance in NEI 05-01 or accepted practices from the 

45 NUREG-1150 studies and are therefore appropriate for the purposes of the SAMA evaluation.

46 Exelon used site-specific meteorological data for the 2008 calendar year as input to the 

47 MACCS2 code. The development of the meteorological data is discussed in Section 3.7 of 

48 Attachment F to the ER. The data were collected from onsite meteorological monitoring 
Appendix F

F-19

1 systems. In response to an NRC staff RAI (Exelon 2014), Exelon clarified that only mixing layer 

2 height was based on other meteorological data. The mixing layer height was based on an EPA

3 study (Holzworth 1972) and identified in Section F.3.7 of the ER. Missing data were filled in by 

4 substituting data from a different elevation, interpolation, power law, or substituting data from 

5 the previous or subsequent day. Sensitivity analyses were performed using MACCS2 and the 

6 meteorological data for the years 2009 and 2010 (Exelon 2013b). The year 2009 data resulted 

7 in a decrease in dose risk of 4 percent and a decrease in cost risk of 2 percent. The year 2010 

8 data resulted in a decrease in dose risk of 1 percent and a decrease in cost risk of 2 percent. 

9 Because the overall results of previous SAMA analyses reviewed by the NRC staff have shown 

10 little sensitivity to year-to-year differences in meteorological data, the NRC staff concludes that 

11 the use of the 2008 meteorological data in the SAMA analysis is reasonable.

12 The population distribution the applicant used as input to the MACCS2 analysis was estimated 

13 for the year 2046 using year 2000 census data as accessed by SECPOP2000 (Bixler 

14 et al. 2003) as a starting point. The transient population was included in the 10-mi (20-km) 

15 emergency planning zone (EPZ), and in the population projection from year 2000 to year 2046. 

16 In addition, special facilities population was also included in the initial year 2000 population 

17 estimate. In response to an NRC staff RAI, Exelon provided the year 2000 transient, special 

18 facility, and residential population distributions (Exelon 2014). These are presented in 

19 Tables 4b-2 and 4c-2 of the RAI response. A 30-year population growth rate was estimated 

20 using the year 2000 SECPOP2000 data and population growth estimates from the Illinois 

21 (IDOC 2012), Wisconsin (WDOA 2012), and Iowa (SDCI 2012) county population projections to 

22 year 2030. The year 2030 population estimate was then scaled to year 2046 using this growth 

23 rate to obtain the distribution in 2046. NRC staff noticed that Section 2.6.1 of the ER contained 

24 year 2010 census population, but that the SAMA analysis used year 2000 census data for 

25 estimating population growth. In response to an NRC staff RAI, Exelon compared a projected 

26 year 2010 population to the recently available year 2010 census population. The projected 

27 population within the 50-mi (80-km) radius was slightly less than, but within, 2 percent of the 

28 census population (Exelon 2014). The baseline population was determined for each of 160 

29 sectors, consisting of 16 directions for each of 10 concentric distance rings to a radius of 50 mi

30 (80 km) surrounding the site. Individual county growth rates were applied at each grid element. 

31 Some grid elements include land from multiple counties. A weighted growth rate was used for 

32 those grid elements based on the fraction of land in that grid element associated with each 

33 county. Counties that were projected to have negative growth rates were conservatively 

34 assumed to have zero growth rates. In response to an NRC staff RAI, Exelon stated that 

35 three recently publicized SECPOP2000 code errors were accounted for in the Byron analysis 

36 (Exelon 2014). Exelon performed a sensitivity study for the year 2046 population by increasing 

37 the population by 30 percent (uniformly). The resulting dose risk increased by 28 percent and 

38 cost risk increased by 26 percent. Because population census data and population growth data 

39 specific to the location of the Byron plant was used, the NRC staff considers the methods and 

40 assumptions for estimating population reasonable and acceptable for purposes of the SAMA 

41 evaluation.

42 The emergency evacuation model was modeled as a single evacuation zone and stated to

43 extend out 10 mi (16 km) from the plant (the EPZ) (ET 2003). Exelon assumed that 95 percent 

44 of the population would evacuate. This assumption is conservative relative to the 

45 NUREG–1150 study (NRC 1990), which assumed evacuation of 99.5 percent of the population 

46 within the EPZ. The evacuated population was assumed to move at an average radial speed of 

47 approximately 4.4 m/s (9.8 miles per hour (mph)) with a delayed start time of 115 minutes after 

48 declaration of a general emergency (Exelon 2013b). The evacuation speed is a time-weighted 

49 average value accounting for season, day of week, time of day, and weather conditions 
Appendix F

F-20

1 (ET 2003). A general emergency declaration was assumed to occur when plant conditions 

2 degraded to a point that was judged to be a credible risk to the public. In response to an NRC 

3 staff RAI, Exelon clarified that the evacuation study (ET 2003) does not associate specific 

4 events with the evacuation time study (Exelon 2014). Exelon performed sensitivity studies for 

5 the evacuation speed and delay time to evacuation. The evacuation speed was reduced by 

6 50 percent to 2.2 m/s (4.9 mph). The resulting dose risk increased by 2 percent and the change 

7 in cost risk was negligible. The evacuation delay time was increased by a factor of 2 to 

8 230 minutes. The resulting dose risk decreased by 0.1 percent and the change in cost risk was 

9 negligible. The NRC staff concludes that the evacuation assumptions and analysis are 

10 reasonable and acceptable for the purposes of the SAMA evaluation. 

11 Site-specific agriculture and economic parameters were developed manually using data in the 

12 2007 National Census of Agriculture (USDA 2009) and 2007 data from the Bureau of Economic 

13 Analysis (BEA 2012) for each of the 21 counties surrounding Byron, to a distance of 50 mi

14 (80 km). Economic values were updated to July 2012 using the consumer price index from the 

15 Bureau of Labor Statistics (BLS 2012). The values used for each of the 160 sectors were the 

16 data from each of the surrounding counties multiplied by the fraction of that county’s area that 

17 lies within that sector. Food ingestion was modeled using the new MACCS2 ingestion pathway 

18 model COMIDA2 (Chanin and Young 1998). For Byron, approximately 5.6 percent of the total 

19 population dose risk is due to food ingestion (approximately 2 person-rem/year) (Exelon 2013b). 

20 In response to an NRC staff RAI, Exelon stated that input parameters used were based on food 

21 production parameters derived from annual food consumption of an average individual, and that 

22 food ingestion dose limits were based on 1998 Food and Drug Administration Guidance 

23 (Exelon 2014). Generic economic data that is applied to the region as a whole were revised 

24 from the MACCS2 sample problem input in order to account for cost escalation since 1986, the 

25 year that input was first specified. A factor of 2.09, representing cost escalation from 1986 to 

26 July 2012, was applied to parameters describing cost of evacuating and relocating people, land 

27 decontamination, and property condemnation. 

28 Exelon performed a sensitivity study for the economic rate of return, resettlement planning, and 

29 generic economic inputs. The rate of return was modified to 3 percent as identified in the NRC’s 

30 comments (NRC 2005b) on Nuclear Energy Institute (NEI) 05-01, “Severe Accident Mitigation 

31 Alternative (SAMA) Analysis Guidance Document” (Revision A) (NEI 2005), and 12 percent, the 

32 value used in NUREG-1150 MACCS2 analyses, from the base case of 7 percent, consistent 

33 with NRC guidance (NRC 2004). The decrease in rate of return (by approximately 57 percent) 

34 resulted in an increase in population dose of 1 percent and a decrease in cost risk of 9 percent. 

35 The increase in rate of return (by approximately 71 percent) resulted in a decrease in population 

36 dose of 2 percent and an increase in cost risk of 10 percent. Resettlement planning was 

37 modified assuming no “Intermediate Phase” and a 1-year “Intermediate Phase” (in lieu of 6 

38 months). The no intermediate phase resulted in an increase in dose risk of 17 percent and a 

39 decrease in cost risk of 32 percent. A 1-year intermediate phase resulted in a decrease in dose 

40 risk of 14 percent and an increase in cost risk of 35 percent. Key generic economic input 

41 parameters to MACCS2 were modified as shown in Table F.7-1 of the ER. In general, the input 

42 variables were increased by a factor of 2. The increase in these economic parameters resulted 

43 in a decrease in dose risk of approximately 6 percent, and an increase in cost risk of 

44 approximately 48 percent.

45 The NRC staff reviewed the applicant’s methods and assumptions for estimating offsite 

46 consequences, including the results of several sensitivity analyses on parameter assumptions, 

47 and determined that Exelon satisfactorily addressed NRC staff RAIs, that the methods and 

48 parameters follow accepted practices, and that offsite consequences are not very sensitive to 

49 individual parameter assumptions. Therefore, the NRC staff concludes that the methodology 
Appendix F

F-21

1 used by Exelon to estimate the offsite consequences for Byron provides an acceptable basis 

2 from which to proceed with an assessment of risk reduction potential for candidate SAMAs. 

3 Accordingly, based on the NRC staff’s conclusions regarding the internal events CDF model, 

4 treatment of external events, Level 2 fission product release analysis, and Level 3 offsite 

5 consequence analysis, the NRC staff based its assessment of offsite risk on the CDF, offsite 

6 population doses, and offsite economic costs reported by Exelon.

7 F.3 Potential Plant Improvements

8 The process for identifying potential plant improvements, an evaluation of that process, and the 

9 improvements evaluated in detail by Exelon are discussed in this section.

10 F.3.1 Process for Identifying Potential Plant Improvements 

11 Exelon’s process for identifying potential plant improvements (SAMAs) consisted of the 

12 following elements:

13 • review of the most significant basic events from the current plant-specific 

14 PRA including the 2009 Byron fire analysis,

15 • review of selected cost-beneficial SAMAs from selected plants,

16 • review of potential plant improvements identified in the Byron IPE and IPEE,

17 and

18 • insights from the PRA group. 

19 Based on this process Exelon identified an initial set of 30 candidate SAMAs, referred to as 

20 Phase I SAMAs. In Phase I of the evaluation, Exelon performed a qualitative screening of the 

21 initial list of SAMAs and eliminated SAMAs from further consideration using the following 

22 criteria:

23 • The SAMA is not applicable to Byron plant design. 

24 • The SAMA has already been implemented or its intent met at Byron. 

25 • The SAMA has estimated implementation costs that would exceed the dollar 

26 value associated with completely eliminating all severe accident risk at Byron. 

27 Based on this screening, three SAMAs were eliminated leaving 27 for further evaluation. The 

28 results of the Phase I screening analysis are provided in Table F.5-3 of the ER (Exelon 2013b). 

29 The remaining SAMAs, referred to as Phase II SAMAs, are listed in Table F.6-1 of the ER 

30 (Exelon 2013b). In Phase II, a detailed evaluation was performed for each of the 27 remaining 

31 SAMA candidates, as discussed in Sections F.4 and F.6 below. To account for the potential 

32 impact of external events, the estimated benefits based on internal events were multiplied by a 

33 factor of 2.5 as discussed in Section F.2.2.2. Also as discussed in Section F.2.2.2, this 

34 multiplier was increased to 2.6 in response to an NRC staff RAI (Exelon 2014).

35 F.3.2 Review of Exelon’s Process

36 Exelon’s efforts to identify potential SAMAs focused primarily on areas associated with internal 

37 initiating events. The initial list of SAMAs generally addressed the accident sequences 

38 considered to be important to CDF from functional, initiating event, and risk reduction worth 

39 (RRW) perspectives at Byron.
Appendix F

F-22

1 Exelon provided in the ER a tabular listing of the Level 1 PRA basic events sorted according to 

2 their RRW (Exelon 2013b). The SAMAs impacting these basic events would have the greatest 

3 potential for reducing risk. In the ER, Exelon indicates that the review of these events down to 

4 an RRW of 1.017 would correspond to a potential benefit of $100,000 if a SAMA to mitigate this 

5 event were 100 percent effective. This value is Exelon’s estimate of the cost of a procedure 

6 change along with any necessary engineering analysis and training. As Exelon noted, this 

7 value of the RRW does not include the potential impact of external events, because the Byron 

8 fire results were reviewed separately for potential SAMAs since the fire model is in an interim 

9 state. Nevertheless, Exelon used an RRW cutoff of 1.005 in its review of basic events, which 

10 corresponds to about a half-percent change in CDF given 100-percent reliability of the SAMA. 

11 The NRC staff estimates that this equates to a benefit of approximately $80,000 (after the 

12 benefits have been multiplied by a factor of 2.6 to account for external events). 

13 Exelon also provided in the ER tabular listings of the Level 2 PRA basic events for the combined 

14 LERF categories and the combined Late Release categories, which in total contribute 

15 approximately 95 percent population dose risk and OECR. Exelon also used an RRW cutoff of 

16 1.005 when reviewing these basic events for SAMA candidates. The Level 2 sequences for the 

17 intact release category were not included in the review so as to prevent high frequency–low 

18 consequence events from biasing the importance listing. 

19 Exelon’s review of the Level 1 and Level 2 importance lists resulted in the identification of 

20 26 SAMA candidates.

21 In its review of these importance lists and the SAMAs identified by Exelon, the NRC staff noted 

22 the following (NRC 2014): 

23 • In ER Table F.5-1, for basic event 0VA1SUPP----PNMM “UNIT 1 VA 

24 SUPPLY PLENUM MAINTENANCE,” the only SAMA identified is SAMA 4, 

25 Installation of the “no-leak” RCP seals. The NRC staff suggested a 

26 potentially lower cost SAMA to “provide portable ventilation during 

27 maintenance activities.” 

28 • In ER Table F.5-1 basic events “1AP-142-1---TRMM” and “1AP-142-2---

29 TRMM” appear to result in the unavailability of the same equipment, namely 

30 the startup FW pump and the same condensate pumps. The NRC staff 

31 determined that this implies that both system auxiliary transformers (SATs) 

32 are needed and suggested an alternative SAMA to temporarily align an 

33 alternate power source to the FW system while this maintenance is under

34 way.

35 In response to the RAIs on these issues, Exelon indicated that for basic event 0VA1SUPP----

36 PNMM current plant procedures already direct the alignment of portable fans for CVCS pump 

37 room cooling in loss of SX scenarios, which represent 96 percent of the contributors including 

38 the 0VA1SUPP----PNMM event. The step to align the portable fans is included in the human 

39 failure event (HFE) for establishing alternate lube oil cooling to the CV pumps, which is 

40 successful in these scenarios. However, Exelon also stated that the portable fans are not 

41 currently credited in the PRA model because there is no basis for assuming they would provide 

42 adequate CV pump room cooling (Exelon 2014). Since Exelon already includes providing for 

43 portable ventilation in plant procedures and is committed to installing the “no-leak” seals, the 

44 NRC staff concludes that this possible alternative SAMA, to provide portable ventilation during 

45 maintenance activities, has been adequately explored and is unlikely to be cost-beneficial.

46 Regarding basic events 1AP-142-1---TRMM and 1AP-142-2---TRMM, Exelon indicated that 

47 these events involve the availability of the 142-1 and 142-2 SATs. On a plant trip, the balance 
Appendix F

F-23

1 of plant loads normally supplied by the unit auxiliary transformers (UATs) are transferred to the 

2 associated SATs. If, however, a SAT is out of service for maintenance the transfer is disabled 

3 because of the potential for overloading the single available SAT. Because of the load 

4 limitations on a single SAT, there are no viable temporary power alignments that could be 

5 implemented during SAT maintenance using existing hardware. The loads supplied by the UAT

6 could not be prealigned to the available SAT (load limit issue) and the UATs would be

7 deenergized after a plant trip. The opposite unit’s SAT can be tied to the non-Class 1E bus

8 through the Class 1E busses, but nonaccident operation in this configuration is not desirable

9 because of the potential for a single fault to fail a division of power on both units (Exelon 2014). 

10 Based on this additional information, the NRC staff concludes that Exelon adequately 

11 considered and properly rejected the suggested alternative SAMA. 

12 The Exelon review of the late release categories importance list identified SAMA 24, to provide 

13 a reactor vessel cooling system to prevent vessel melt-through, as a means of mitigating 

14 basemat melt-through. The NRC staff noted that based on the Byron IPE (ComEd 1994), plant 

15 procedures were implemented to direct reactor cavity flooding in core damage scenarios to 

16 provide a means of exterior vessel cooling. Based on the IPE implementation of cavity flooding, 

17 the NRC staff requested clarification as to why the additional cooling system in SAMA 24 was 

18 required to perform this function. Exelon noted that for cases in which core damage occurred, 

19 there was a concern that it might not be possible to perform cavity flooding in the time available 

20 to prevent vessel failure. Preventing reactor vessel melt-through not only prevents basemat 

21 melt-through but also prevents CFEs such as those due to direct containment heating. A 

22 fast-acting system might therefore have added benefit. These additional failures were assumed 

23 to be mitigated by SAMA 24 in the ER cost-benefit analysis. The NRC staff considers this 

24 description of SAMA 24 and the explanation of its potential benefit to be reasonable.

25 Exelon reviewed the cost-beneficial Phase II SAMAs from prior SAMA analyses for six 

26 Westinghouse PWR sites to aid in the identification of additional SAMA candidates. Many of the 

27 industry Phase II SAMAs were already represented by other SAMAs in the Byron list, were 

28 known not to impact important plant systems or be relevant to the Byron design, or were judged 

29 not to have the potential to be close contenders for Byron. As a result, Exelon did not add most 

30 of the SAMAs in these prior analyses to the Byron SAMA list. However, Exelon’s review 

31 resulted in the identification of one additional SAMA candidate, SAMA 26.

32 The NRC staff noted in an RAI that the NRC staff’s evaluation of the Indian Point, Units 2 and 3, 

33 SAMA analysis (NRC 2010a) identified 13 potentially cost-beneficial SAMAs for Indian Point 

34 Unit 2, whereas the Byron review considered only 7 of the 13 SAMAs (NRC 2014). In response 

35 to the RAI, Exelon assessed the additional six Indian Point Unit 2 SAMAs and concluded that 

36 each either is not applicable to the Byron design, is implemented at Byron, or is already 

37 addressed by a Byron candidate SAMA (Exelon 2014).

38 In its review of industry cost-beneficial SAMAs, Exelon noted that two Vogtle SAMAs (SAMAs 6 

39 and 16) (NRC 2008) that were originally cost-beneficial were, upon further evaluation of the cost 

40 and benefit, judged to not be cost-beneficial at Vogtle. In response to an NRC staff RAI to 

41 consider if these SAMAs would be applicable or potentially cost-beneficial at Byron, Exelon 

42 determined that the failure being mitigated by Vogtle SAMA 6 (involving adding a bypass line 

43 around the cooling tower return valve) is not a significant risk contributor for Byron and the 

44 SAMA would not be cost-beneficial. For Vogtle SAMA 16 (involving nonexplicit improvements in 

45 ISLOCA procedures), Exelon determined that the intent of this SAMA is already met by existing 

46 Byron ISLOCA procedures that are constantly trained on and improved by the plant staff 

47 (Exelon 2014). Based on this additional information, the NRC staff concludes that Vogtle 

48 SAMAs 6 and 16 have been adequately explored and are unlikely to be cost-beneficial at Byron. 
Appendix F

F-24

1 Exelon considered the potential plant improvements described in the IPE in the identification of 

2 plant-specific candidate SAMAs for internal events. As described in the ER, while the Byron 

3 IPE did not identify any vulnerabilities nor provide a definitive list of enhancements, the report 

4 did describe a multisite review of IPE and Accident Management insights. The ER indicated 

5 that the IPE discussed two enhancements, both of which have been implemented at Byron 

6 (Exelon 2013b).

7 The NRC staff noted in an RAI that, according to the NRC staff SER for the IPE (NRC 1997b),

8 the transmittal of the modified Byron IPE indicated that a potential vulnerability involving a 

9 dual-unit loss of emergency service water (ESW) due to internal flooding had been identified 

10 and that a modification was being considered (NRC 2014). In response to the RAI, Exelon 

11 indicated that this modification has not been implemented but is included as SAMA 10 (to alter 

12 the ductwork between the auxiliary building sump drain room and the SX pump room) in the 

13 SAMA analysis (Exelon 2014).

14 In response to an NRC staff RAI, Exelon indicated that, as part of routine work, PRA groups 

15 identify major contributors to plant risk, and, in some cases, the groups have identified specific 

16 changes that could reduce risk. As part of the SAMA identification process, the site PRA group 

17 was questioned by the applicant’s SAMA evaluation team to determine if they have identified 

18 any such changes. For Byron, the PRA group did not identify any plant enhancements that 

19 were not already identified by the SAMA identification process (Exelon 2014).

20 In response to an NRC staff RAI that asked Exelon to describe the steps taken to identify 

21 SAMAs involving improvements in procedures, training, or available cues for the important 

22 human errors, Exelon indicated that the HRA quantifications are reviewed to identify the major 

23 contributors to the HEP and to determine if there are any practical means of reducing those 

24 contributors. Byron SAMAs 7 and 8 are examples of the results of this process (Exelon 2014).

25 As discussed above in Section F.2.2.1, the NRC staff noted some differences in PRA results for 

26 the Byron site compared to the similar Braidwood site. Exelon indicated that for certain 

27 sequences resulting from RCP seal LOCAs, for which the Byron CDF is considerably larger 

28 than that for Braidwood, the difference is due to a different normal alignment of the SX crosstie 

29 valves at Byron which requires additional operator actions. Exelon indicated that the planned 

30 installation of “no-leak RCP seals” would make RCP seal failures noncontributors, and thus a 

31 SAMA to change the Byron valve alignment would not be needed. Exelon further indicated that, 

32 without the installation of the no-leak RCP seals, changing the Byron normal operation to be

33 consistent with Braidwood would be cost-beneficial. Exelon indicated that it has previously 

34 considered changing the Byron valve alignment, but no changes were made because of

35 considerations unrelated to PRA insights (Exelon 2014). Based on Exelon’s planned 

36 implementation of SAMA 4, install “no-leak” RCP seals, the NRC staff concludes that a SAMA to 

37 change the normal position of the SX crosstie valves has been adequately explored and is 

38 unlikely to be cost-beneficial.

39 Based on this information, the NRC staff concludes that the set of SAMAs evaluated in the ER, 

40 together with those identified in response to NRC staff RAIs, addresses the major contributors 

41 to internal event CDF. 

42 As discussed above, risk insights from the 2009 Bryon fire PRA were used to identify SAMA

43 candidates. Since the fire model was not fully integrated with the most recent Levels 2 and 3 

44 analyses and the model was based on Revision 6C of the internal events PRA rather than the 

45 current Revision BB11b1 model, it could not be used directly in the identification of SAMAs. 

46 However, the fire contributors that are potentially significant to risk were reviewed to identify 

47 potential SAMAs. Exelon considered and evaluated the fire zones with a CDF contribution 
Appendix F

F-25

greater than the IPEEE screening threshold of 1.0×10−6 1 per year for potential SAMAs. These 

2 fire zones are listed in Table F-4.

3 The major fire scenario results for each zone were reviewed and grouped together to help 

4 identify target equipment that is common to multiple scenarios in a given fire zone. In response 

5 to an NRC staff RAI, Exelon defined major fire scenarios as those contributing 10 percent or 

6 more to the fire zone frequency (Exelon 2014). The major scenarios of each of the important 

7 fire zones are described and potential SAMAs identified in Section F.5.1.6.1 of the ER. Exelon’s 

8 review of the major fire scenarios indicated that several of the SAMAs identified to mitigate 

9 internal event risks would also mitigate fire-initiated accidents. In addition, Exelon’s review of 

10 the major fire risk contributors resulted in the identification of three additional SAMA candidates 

11 to mitigate fire-initiated accidents. 

The NRC staff estimates that the CDF screening value of 1.0×10−6 12 per year equates to a benefit 

13 of approximately $110,000 at a 7 percent discount rate. Because $110,000 is essentially 

14 equivalent to Exelon’s estimate of $100,000 as the cost of a procedure change, the NRC staff 

considers the CDF screening threshold of 1.0×10−6 15 per year for potential fire-mitigating SAMAs

16 reasonable.

17 The NRC staff notes that for four fire zones in Unit 1 and for six fire zones in Unit 2 Exelon 

18 states, “Because the fire is a ‘bounding’ scenario, fire scenarios are not developed for all of the 

19 specific ignition sources in the fire zone, which limits the potential for fire specific SAMA

20 identification.” In an RAI, the NRC staff noted that Fire Zone U2: 11.6-2, the largest contributor 

21 to Unit 2 fire CDF, is analyzed using a bounding scenario and asked Exelon to discuss whether 

22 or not insights from the analysis of the same or similar fire zone in Unit 1 can be used to identify 

23 potential fire-specific SAMAs. Exelon responded that the Unit 1 counterpart of Fire Zone 11.6-2 

24 (Division 22 containment electrical penetrations area) is Fire Zone 11.6-1 (Division 12 

25 containment electrical penetrations area), which was also analyzed as a bounding fire and 

26 therefore does not provide any additional insights related to fire sources or propagation (Exelon 

27 2014).

28 Regarding Fire Zone U1: 11.6c-0 (the auxiliary building laundry room), the NRC asked Exelon 

29 to consider a SAMA to move the laundry to another facility if the fire source in the fire zone is 

30 due to laundry room operation (NRC 2014). In response to the RAI, Exelon indicated that the 

31 laundry equipment has been removed from that room and this room no longer serves that 

32 function (Exelon 2014).

33 In response to an NRC staff RAI that asked Exelon to describe the extent to which new or 

34 improved Byron fire procedures mitigate the important fires have been considered in the SAMA

35 analysis, Exelon responded that review of the fire procedures to identify improvements in the 

36 fire response is an iterative task that is performed as part of the fire PRA development process 

37 and is not within the scope of the SAMA analysis (Exelon 2014). Unlike SAMAs to modify 

38 Abnormal Operating Procedures and Emergency Operating Procedures, the identification of fire 

39 response enhancement requires coordination with the fire modeling team and procedure writers 

40 to ensure the actions are consistent with existing procedures and that the proposed changes 

41 are appropriate for the failure modes caused by the fire events (Exelon 2014). The NRC staff 

42 concludes that further consideration of new or improved fire procedures is not necessary for the 

43 Byron SAMA evaluation, while acknowledging the following:

44 • The NRC staff cannot conclude that identifying improvements to the fire 

45 procedures is beyond the scope of a SAMA analysis since the applicant’s 

CDF screening threshold of 1.0×10−6 46 per year essentially equates to Exelon’s 

47 estimate of the cost of a procedure change.
Appendix F

F-26

1 • Exelon evaluated all fire zones having a CDF contribution greater than the 

2 screening threshold for potential SAMAs, 

3 As discussed in Section F.2.2.2, although the IPEEE did not identify any fundamental 

4 vulnerabilities or weaknesses related to external events, several “outliers” were identified from 

5 the IPEEE seismic assessment (ComEd 1996). These “outliers” were addressed in the ER and 

6 described as “generally items with potential seismically induced interaction issues for which it 

7 was difficult to calculate a High Confidence of Low Probability of Failure value” (Exelon 2013b). 

8 Exelon described each of the items and their disposition, concluding that no additional SAMAs 

9 were needed to address these items. In response to an NRC staff request for clarification of the 

10 disposition of these outliers, Exelon provided additional information on each outlier and 

11 concluded that each has been dispositioned without the need for additional SAMAs 

12 (Exelon 2014).

13 As stated earlier, the Exelon IPEEE analysis of other external hazards (high winds, tornadoes, 

14 external floods, and other external events) did not identify opportunities for improvements for 

15 these events.

16 The NRC staff notes that the Byron external flooding design and capability, seismic design and 

17 capability, and the IPEEE seismic “outliers” were assessed in the engineering walkdowns and 

18 evaluations required for the response to the Fukushima Near-Term Task Force’s 

19 Recommendation 2.3 (Exelon 2012; NRC 2012; Sargent 2012).

20 An NRC staff RAI questioned Exelon about potentially lower cost alternatives to some of the 

21 SAMAs evaluated (NRC 2014), including:

22 • A SAMA to modify procedures to avoid clearing of RCS cold leg water seals 

23 in the event of core damage. In response to the RAI, Exelon explained that 

24 this improvement has already been implemented at Byron because the Byron 

25 procedures direct an “RCP bump” to inject reactor coolant line water into the 

26 reactor vessel only if the SG level is greater than 10 percent which avoids the 

27 clearing of the RCS cold leg seal (Exelon 2014). 

28 • An SG PORV gagging device for use after an SGTR and stuck-open SG 

29 PORV as an alternate to SAMA 14. In response to the RAI, Exelon explained 

30 that the Byron design includes isolation valves with manual handwheels 

31 upstream of the SG PORVs, hence the ability to stop flow through a 

32 stuck-open PORV exists without the need for the gagging device

33 (Exelon 2014). 

34 • Install “reduced leakage” RCP seals similar to those evaluated for Vogtle 

35 SAMA 7 (NRC 2008) as an alternative to the “no-leakage” seals evaluated as 

36 Byron SAMA 4. In response to the RAI, Exelon explained that this is not a 

37 viable alternative for Byron because (1) Exelon already decided to implement 

38 SAMA 4 at Byron, (2) Exelon already made awards for the replacement of the 

39 RCP seals, and (3) the cost of engineering and analysis already exceeded 

40 the cost given for the Vogtle “reduced leakage” RCP seals (Exelon 2014). 

41 • Installation of additional flood alarms to assist in mitigating important internal 

42 flood scenarios. In response to the RAI, Exelon reviewed the internal 

43 flooding events and determined that internal flooding alarms already existed

44 or were evaluated in an existing SAMA (SAMA 16), or determined that the 

45 flooding sequences are not risk significant (Exelon 2014). 
Appendix F

F-27

1 The NRC staff concludes that Exelon used a systematic and comprehensive process for 

2 identifying potential plant improvements for Byron, and that the set of potential plant 

3 improvements identified by Exelon is reasonably comprehensive and, therefore, acceptable. 

4 This search for SAMA candidates by Exelon included reviewing insights from the plant-specific 

5 risk studies, and reviewing plant improvements considered in previous SAMA analyses. While 

6 explicit treatment of external events other than fire events in the SAMA identification process 

7 was limited, the NRC staff determined that the prior implementation of plant modifications

8 identified in the IPEEE and the absence of external event vulnerabilities reasonably justify

9 examining primarily the internal and fire events risk results for this purpose. 

10 The NRC staff also notes that the set of SAMAs submitted by Exelon is not all-inclusive, since 

11 additional, possibly even less expensive, design alternatives could be postulated. However, 

12 because Exelon’s SAMA identification process included reviewing all basic events and fire 

13 zones having CDF values greater than or equal to the cost of a procedure change, the NRC 

14 staff concludes that the benefits of any additional modifications are unlikely to exceed the 

15 benefits of the modifications evaluated and that the alternative improvements would not likely 

16 cost less than the least expensive alternatives evaluated, when the subsidiary costs associated 

17 with maintenance, procedures, and training are considered.

18 Exelon’s SAMA ID process included reviewing insights from the plant-specific risk studies, and 

19 reviewing plant improvements considered in previous SAMA analyses. While explicit treatment 

20 of external events in the SAMA identification process was limited, the NRC staff determined that 

21 the prior implementation of plant modifications and the absence of external event vulnerabilities 

22 reasonably justify examining primarily the internal events risk results for this purpose.

23 F.4 Risk Reduction Potential of Plant Improvements

24 Exelon evaluated the risk-reduction potential of the 27 SAMAs retained for the Phase II 

25 evaluation in the ER (Exelon 2013b). The SAMA evaluations were generally performed by 

26 Exelon in a realistic or conservative fashion that overestimates the benefit of the SAMA. In 

27 most cases, the failure likelihood of the added equipment is taken to be optimistically low, 

28 thereby overestimating the benefit of the SAMA. In other cases, it was assumed that the SAMA 

29 eliminated all of the risk associated with the proposed enhancement. The NRC staff notes that 

30 this bounding approach overestimates the benefit and is conservative.

31 Exelon used model requantification to determine the potential benefits for most of the SAMAs. 

32 The CDF, population dose reductions, and offsite economic cost reductions were estimated 

33 using the Byron PRA model. The changes made to the model to quantify the impact of each 

34 SAMA are described in Section F.6 of the ER for each SAMA. Table F–5 summarizes the 

35 assumptions used to estimate the risk reduction for each of the evaluated SAMAs, the 

36 estimated risk reduction in terms of percent reduction in CDF, population dose, and offsite 

37 economic cost, and the estimated total benefit (present value) of the averted risk. The 

38 determination of the benefits for the various SAMAs is further discussed in Section F.6 of this 

39 appendix. 

40 The NRC staff reviewed the assumptions used in evaluating the benefit or risk reduction 

41 estimate of each of the SAMAs as described in the ER Section F.6. In response to an NRC 

42 staff RAI, Exelon clarified that for SAMA 14, automating the refueling water storage tank 

43 (RWST) makeup, it is conservatively assumed for both SGTR and non-SGTR sequences that 

44 transitioning to recirculation mode and terminating break flow (i.e., controlled cooldown) is 

45 required. The human errors associated with both of these scenarios are reduced by a factor of 

46 10 as a result of the additional time available due to this SAMA (Exelon 2014). In response to 

47 another NRC staff RAI, Exelon clarified that for SAMA 15, interunit AFW crosstie, no credit is 
Appendix F

F-28

1 taken for this during dual-unit events since each unit may require use of its own AFW pump 

2 (Exelon 2014). The NRC staff considers the assumptions, as clarified, to be reasonable and 

3 acceptable for purposes of the SAMA evaluation because they yield conservative results. 

4 For those SAMAs that specifically mitigate fire risk (i.e., SAMAs 27, 28, 30, and 31), a bounding 

5 estimate of the SAMA benefits was made. Exelon conservatively assumed that all of the fire

6 risk, or fire CDF, associated with the fire zones affected by the SAMA is eliminated. (Because 

7 population dose risk and OECR were not directly calculated, this is noted as “Not Estimated” in 

8 Table F–5). Exelon assumed these SAMAs have no additional benefits in internal events. The 

9 NRC staff notes that this approach is not necessarily conservative for SAMAs in which the 

10 benefit is dominated by the reduction in population dose risk or offsite economic cost risk and 

11 not CDF. However, the NRC staff concludes that, since all of the fire mitigating SAMAs were 

12 determined by Exelon to be potentially cost-beneficial, further evaluation of these SAMAs is not 

13 necessary. 

14 The NRC staff has reviewed Exelon’s bases for calculating the risk reduction for the various 

15 plant improvements and concludes, with the above clarifications, that the rationale and 

16 assumptions for estimating risk reduction are reasonable and generally conservative (i.e., the 

17 estimated risk reduction is higher than what would actually be realized). Accordingly, the NRC 

18 staff based its estimates of averted risk for the various SAMAs on Exelon’s risk reduction 

19 estimates.
F-29

Table F–5. SAMA Cost/Benefit Screening Analysis for Byron Station(a) 1 

SAMA Modeling Assumptions

% Risk Reduction Total Benefit 

CDF Population

Dose OECR

Baseline 

(Internal + 

External)

Base

Unc

1 – Install diesel driven SX pump in a 

new dedicated building (c)

Reduce the probability of 

diesel-driven SX pump failure 

to 1×10−2.

63 80 89 12.8M 32M 

2 – Replace the positive 

displacement pump with a 

self-cooled, auto-start pump

Reduce the probability of RCP 

seal failure on loss of SX. 

Seal injection pump failure is 

1×10−3; transfer switch is 

100% reliable.

66 30 14 4.0M 10.2

3 – Auto-start of standby SX pump

Reduce the probability of loss 

of cooling to critical loads on 

failure of standby SX to start. 

Auto start failure is 1×10−4.

19 14 9 1.8M 4.5M 

4 – Install “no leak” RCP seals

Reduce the probability of RCP 

seal for loss of seal cooling. 

Seal failure probability is 

reduced by a factor of 1,000.

67 31 15 4.3M 10.6

5 – Modify the startup feedwater 

pump to start using the AMSAC SG 

low-low-low level signal to mitigate 

AFW failure

Modify FW pump start logic to 

require failure of both the 

automated start function and 

manual operator action. Auto 

start failure is 1×10−4.

9 21 31 3.9M 9.7M 

7 – Establish flow to the residual 

heat removal (RHR) HX on RHR 

pump start

Modify procedures to 

preclude the need for 

continuous action statement 

to protect RHR pumps. 

Reduce HEP from 7.3×10−4 to 

1.4×10−4.

2 <1 <1 77K 190
F-30

SAMA Modeling Assumptions

% Risk Reduction Total Benefit 

CDF Population

Dose OECR

Baseline 

(Internal + 

External)

Base

Unc

8 – Install kill switches for the fire 

protection pumps in the MCR

Reduce the HEP for 

termination of fire pump flow. 

Action time is assumed to be 

1 minute per pump.

4 3 2 331K 825

9 – Install flow restrictors in fire 

protection pipes

Aux building fire break flow is 

reduced to 1,000 gpm, and is 

adequate to meet fire 

suppression requirements. 

The increase in available time 

to terminate flow reduces the 

flood mitigation factor to 

1.2×10−4.

8 6 3 709K 1.8M 

10 – Alter ductwork between the Aux 

BLDG room and the SX pump room

Completely eliminates the 

“T1” flooding scenario. Flood 

mitigation factors for normal 

SW and SX floods are 

simplified to HEP for 

termination of flooding before 

reaching elevation 364′.

12 12 11 1.7M 4.3M 

11 – Implement diverse mitigation

system (DMS)

A portable 480V generator is 

aligned to support 

diesel-driven AFW makeup or 

a portable SG makeup pump. 

Failure probability for this 

function is 1×10−2. Cognitive 

failure to diagnose the need 

for secondary cooling, and 

any dependent combinations, 

are assumed to fail DMS.

88 80 87 13.4M 33M 
F-31

SAMA Modeling Assumptions

% Risk Reduction Total Benefit 

CDF Population

Dose OECR

Baseline 

(Internal + 

External)

Base

Unc

13 – Alternate AFW cooling with seal 

protection

Eliminates SX dependence for 

motor-driven AFW pump 

operation. Reduce the 

probability of RCP seal failure 

on loss of SX. Seal injection 

pump failure is 1×10−3

; 

transfer switch is 100% 

reliable.

86 80 88 13.4M 33M 

14 – Automate RWST makeup

Reduce HEPs for transition to 

recirculation mode and terminate 

break flow by a factor of 10. 

Reduce impacted joint HEPs 

(JHEPs) to 0 or by a factor of 10.

1 <1 <1 71K 176

15 – Resolve regulatory issues and 

complete implementation of the 

interunit AFW crosstie

The AFW crosstie action 

execution failure probability is 

reduced to 2.4×10−2.

2 2 3 417K 1M 

16 – Install high flow sensors on the 

non-SX system

Completely eliminates all risk 

associated with SW flood 

event scenarios.

2 5 6 823K 2M 

17 – Use AMSAC for alternate low SG 

level AFW initiation

Eliminates the independent 

manual AFW initiation HFE in 

conjunction with all associated 

JHEPs. The AMSAC logic is 

100% reliable.

<1 <1 <1 26K 65K 

18 – Automate refill of the diesel-driven 

AFW pump fuel oil day tank

Eliminates the independent HFE 

and all dependent combinations 

to refill the AFW pump fuel oil 

day tank. The AMSAC logic is 

100% reliable.

<1 <1 <1 78K 194
F-32

SAMA Modeling Assumptions

% Risk Reduction Total Benefit 

CDF Population

Dose OECR

Baseline 

(Internal + 

External)

Base

Unc

19 – Replace MOVs in the RHR 

discharge line with valves that can 

isolate an ISLOCA event

Completely eliminates all risk 

from the ISLOCA events 

occurring in the RHR 

discharge lines.

<1 10 4 637K 1.6M 

20 – Disallow online RHR maintenance Eliminates all risk associated 

with RHR maintenance events. <1 <1 <1 16K 40k 

21 – Install an emergency isolation 

valve in each of the RHR suction lines

Completely eliminates all risk 

from the ISLOCA events 

occurring in the RHR discharge

lines.

0 2 1 163K 407

22 – Install the same high flow isolation 

logic used on Valve_CC685 on 

Valve_9438

Completely eliminates all risk 

from the ISLOCA events 

occurring in the RCP thermal 

barrier cooling HXs.

0 1 <1 46K 114

23 – Install a passive hydrogen ignition 

system

Completely eliminates all 

containment failures due to 

hydrogen detonation.

0 <1 <1 40K 99K 

24 – Provide a reactor vessel exterior 

cooling system

Completely eliminates relocation 

of the core to the containment 

floor and eliminates all CFEs. 

Allow scrubbing to maximize 

averted cost.

0 <1 <1 33K 81K 

25 – Install a filtered containment 

vent

The filtered vent reduces the 

consequential dose and 

offsite economic cost 

associated with containment 

overpressure failures by a 

factor of 10.

0 72 79 9.8M 24.5
F-33

SAMA Modeling Assumptions

% Risk Reduction Total Benefit 

CDF Population

Dose OECR

Baseline 

(Internal + 

External)

Base

Unc

26 – DMS using a dedicated 

generator, self-cooled charging 

pump, and a portable AFW pump

Indefinite AFW makeup 

capability and an alternate 

high-pressure injection 

function capable of providing 

alternate seal injection to 

prevent RCP seal LOCAs. The 

frequency of seal LOCA 

sequences is reduced by a 

factor of 100.

88 80 87 13.4M 33M 

27 – Protect RHR, SI and CVCS 

cubicle cooling fan cables in Fire 

Zone 11.3-0

Completely eliminates all of 

the risk associated with Fire 

Zone 11.3-0.

(d) 26 Not Estimated 2.1M 5.2M 

28 – Install fire barriers around Motor 

Control Center (MCC) 134X

Completely eliminates all of 

the risk associated with Fire 

Zone 11.6-0.

(d) 11 Not Estimated 904K 2.3M 

29 – Automate swap to recirculation 

mode

Completely eliminates the 

contribution from the failure to 

swap to recirculation mode.

1 <1 <1 45K 110

30 – Protect AFW cables in the AUX 

building general area, elevation 383′

Completely eliminates all of 

the risk associated with Fire 

Zone 11.4-0.

(d) 7 Not Estimated 571K 1.4M 

31 – Protect cables for 2AF013A, B, 

and D in the AUX building general 

area, elevation 426′

Completely eliminates all of

the risk associated with Fire 

Zone 11.6-0 (unit 2).

(d) 20 Not Estimated 1.6M 4M 
F-34

SAMA Modeling Assumptions

% Risk Reduction Total Benefit 

CDF Population

Dose OECR

Baseline 

(Internal + 

External)

Base

Unc

(a) SAMAs in bold are potentially cost-beneficial.

(b) The estimated benefits and implementation costs were revised in response to NRC staff RAI 3.d, 6.a, and 6.f (Exelon 2014).

(c)

The modeling assumptions for SAMA 1 are provided in Exelon 2013a. The estimated risk reduction for SAMA 1 CDF, population dose

provided in response to NRC staff RAI 3.d (Exelon 2014).

(d)

The risk reduction for fire-mitigating SAMAs was estimated by the NRC staff, utilizing information provided in the ER, as the ratio of th

divided by the total fire CDF of 5.4×10−5 per year.

Key: AFW = auxiliary feedwater; AMSAC = ATWS mitigating system actuation circuitry; CDF = core damage frequency; CFE = early co

CVCS = chemical and volume control system; DMS = diverse mitigation system; FW = feedwater; gpm = gallons per minute; HEP = h

HFE = human failure event; HX = heat exchanger; ISLOCA = interfacing-systems loss-of-coolant accident; JHEP = joint human error p

LOCA = loss-of-coolant accident; MCR = main control room; MOV = motor-operated valve; NRC = U.S. Nuclear Regulatory Commissi

OECR = offsite economic cost risk; RAI = requests for additional information; RCP = reactor coolant pump; RHR = residual heat remo

RWST = refueling water storage tank; SAMA = severe accident mitigation alternative; SG = steam generator; SW = service water; SX 

Sources: Exelon 2013a, 2014
Appendix F

F-35

1 F.5 Cost Impacts of Candidate Plant Improvements

2 In the ER, Exelon estimated the costs of implementing the candidate SAMAs through the 

3 development of Byron-specific cost estimates, the use of industry estimates, and, in some 

4 cases, combinations of these two sources. It was also noted that Byron-specific implementation 

5 costs do include contingency costs for unforeseen difficulties but do not account for any 

6 replacement power costs (RPCs) that may be incurred due to consequential shutdown time 

7 unless specifically noted. In response to an NRC staff RAI, Exelon stated that a consulting firm 

8 was used to develop “order of magnitude” estimates for the cost of SAMA implementation 

9 (Exelon 2014). Details such as cost of equipment, demolition, scaffolding, overtime, 

10 consumables, freight, engineering, etc. were used to develop the costs. Exelon provided the 

11 components of the cost estimates associated with developing supporting procedures, providing 

12 lifelong training, and applicable simulator updates.

13 Exelon also identified in the RAI response that the cost estimates for several SAMAs (SAMAs 2, 

14 3, 4, 5, 8, 9, 10, 11, 13, 16, 17, and 18) were for both Units 1 and 2 rather than for a single unit 

15 (Exelon 2014). Revised implementation cost estimates for each of these SAMAs were provided 

16 on a per unit basis. The corrected implementation costs were utilized in an updated cost-benefit 

17 analysis and are reflected in Table F–5. Detailed cost estimates were not developed for SAMAs 

18 that were judged to have implementation costs that far exceeded the estimated benefit.

19 In response to an NRC staff RAI concerning savings due to sharing of costs between units and 

20 between the Byron and Braidwood sites, Exelon clarified that since implementation costs were

21 developed on a “per site” basis, cost sharing between units was accounted for in the updated 

22 analysis by dividing the “per-site” costs in half to obtain the “per-unit” costs (Exelon 2014). Cost 

23 sharing, however, was not considered between sites. Exelon explained that if cost sharing 

24 between sites were possible, engineering costs at the first sister plant are estimated to be 

25 generally 75 percent to 80 percent of the original costs if the modifications are identical. 

26 However, Exelon indicated that sharing of costs between sites is not appropriate because:

27 • A SAMA implemented at one site will not necessarily be implemented at the

28 other site.

29 • While cost sharing between sites could reduce some implementation costs, 

30 any reductions in cost would be offset if other costs were also accounted for, 

31 such as inflation and RPCs. 

32 • The SAMA designs are conceptual and the cost estimates provided are 

33 “order of magnitude” estimates. Changes in the per-site engineering costs of 

34 12 to 13 percent are expected to be within the margin of error.

35 • Actual installation costs are generally larger than estimated installation costs.

36 • The impact of accounting for intersite cost-sharing is bounded by the results 

37 of the CDF uncertainty analysis, which is discussed in Section F.6.2. 

38 The NRC staff concludes that the amount of cost savings due to sharing of cost between sites is 

39 highly uncertain. The NRC staff also believes that the estimated implementation costs could be 

40 reduced by up to 25 percent if sharing of costs is accounted for between the Byron and 

41 Braidwood sites. However, accounting for a 25 percent reduction in the implementation costs

42 shown in Table F–5 would not result in any additional potentially cost-beneficial SAMAs. Based 

43 on this result, the NRC staff considers the RAI issue concerning savings due to sharing of costs 

44 between units and between the Byron and Braidwood sites resolved.
Appendix F

F-36

1 Exelon estimated that the minimum cost of making a change to a procedure and for conducting 

2 the necessary training on a procedure change to be $100,000. In response to an NRC staff 

3 RAI, Exelon stated that although potentially lower cost estimates could be developed for 

4 procedure changes, all SAMAs associated with procedure changes were found to be 

5 cost-beneficial (Exelon 2014). Since all SAMAs associated with procedure change were found 

6 to be potentially cost-beneficial, reducing the cost of a procedure change to less than $100,000 

7 would have no impact on the SAMA analysis results, and, based on this, the NRC staff finds this 

8 RAI response acceptable. 

9 For SAMAs 12 and 20, an NRC staff RAI requested that Exelon explain why the implementation 

10 cost estimates for these SAMAs assumed an extended outage time rather than assuming 

11 maintenance was performed in parallel with other outage activities (NRC 2014). Exelon 

12 responded that for SAMA 12, the SAT is the primary source of power to systems supporting 

13 spent fuel pool cooling when the fuel is in the spent fuel pool (Exelon 2014). At Byron, SAT 

14 work has not been performed during refueling outages as the refueling unit’s SAT is protected 

15 during the entire outage. Shutdown risk procedures do not allow for SAT work anytime fuel is in 

16 the reactor vessel. The SAT protection could be removed during defueled conditions when the 

17 core fuel is in the spent fuel pool. However, the standard template for the defueled window is 

18 only 32 hours. The proposed SAT maintenance typically requires approximately 14 days to 

19 complete, requiring the outage to be extended. In addition, non-ESF buses are powered by the 

20 SAT that is needed during the outage. Reconfiguration of the SAT would hamper the ability to 

21 perform other normal outage work. Exelon responded that for SAMA 20, the primary driver is 

22 that any work on an RHR train be performed during the defueled window (Exelon 2014). When 

23 fuel is in the reactor vessel, it is desirable to have both RHR trains in service. In addition, while 

24 pump suction and HX work could be done online, the inability to vent the RH pump discharge

25 requires that this work be performed during an outage. The proposed RHR maintenance 

26 typically requires approximately 4 to 5 days to complete, requiring the outage to be extended. 

27 Based on this additional information, the NRC staff considers the estimated costs for SAMAs 12 

28 and 20 to be reasonable and acceptable for purposes of the SAMA evaluation.

29 For certain improvements, the NRC staff compared the cost estimates to estimates developed 

30 elsewhere for similar improvements, including estimates developed as part of other licensees’ 

31 analyses of SAMAs for operating reactors.

32 For SAMA 1, Install a dedicated diesel-driven SX pump, the NRC staff noted that the cost 

33 estimate from the Limerick SAMA analysis used as the basis for the cost estimate included 

34 large HXs and safety-related equipment (PECO 1989). An NRC staff RAI questioned whether 

35 non-safety grade equipment could be considered, and that large HXs significantly increase cost 

36 but are not needed in SAMA 1 (NRC 2014). In response to the RAI, Exelon reevaluated the 

37 cost estimate for SAMA 1 and provided the updated cost, which is included in Table F–5.

38 Given that Exelon followed the guidance in NEI 05-01 (NEI 2005) and satisfactorily addressed 

39 NRC questions regarding cost estimates, the NRC staff concludes that the cost estimates 

40 provided by Exelon are sufficient and appropriate for use in the SAMA evaluation.

41 F.6 Cost-Benefit Comparison

42 Exelon’s cost-benefit analysis and the NRC staff’s review are described in the following 

43 sections.
Appendix F

F-37

1 F.6.1 Exelon’s Evaluation 

2 The methodology used by Exelon was based primarily on NRC’s guidance for performing 

3 cost-benefit analysis, i.e., NUREG/BR–0184, Regulatory Analysis Technical Evaluation 

4 Handbook (NRC 1997c). The guidance involves determining the net value for each SAMA

5 according to the following formula:

6 Net Value = (APE + AOC + AOE + AOSC) − COE, where 

7 APE = present value of averted public exposure ($)

8 AOC = present value of averted offsite property damage costs ($)

9 AOE = present value of averted occupational exposure costs ($)

10 AOSC = present value of averted onsite costs ($)

11 COE = cost of enhancement ($)

12 If the net value of a SAMA is negative, the cost of implementing the SAMA is larger than the 

13 benefit associated with the SAMA and it is not considered cost-beneficial. Exelon’s derivation of 

14 each of the associated costs is summarized below.

15 NUREG/BR–0058 has recently been revised to reflect the agency’s policy on discount rates. 

16 Revision 4 of NUREG/BR–0058 states that two sets of estimates should be developed, one at 

17 3 percent and one at 7 percent (NRC 2004). Exelon provided a base set of results using the 

18 3 percent discount rate and a sensitivity study using the 7 percent discount rate (Exelon 2013b).

19 Averted Public Exposure Costs

20 The averted public exposure (APE) costs were calculated using the following formula:

21 APE = Annual reduction in public exposure (Δ person-rem/year)

22 × monetary equivalent of unit dose ($2,000 per person-rem)

23 × present value conversion factor (15.04 based on a 20-year period with a 

24 3-percent discount rate)

25 As stated in NUREG/BR–0184 (NRC 1997c), it is important to note that the monetary value of 

26 the public health risk after discounting does not represent the expected reduction in public 

27 health risk due to a single accident. Rather, it is the present value of a stream of potential 

28 losses extending over the remaining lifetime (in this case, the renewal period) of the facility. 

29 Thus, it reflects the expected annual loss due to a single accident, the possibility that such an 

30 accident could occur at any time over the renewal period, and the effect of discounting these 

31 potential future losses to present value. For the purposes of initial screening, which assumes 

32 elimination of all severe accidents, Exelon calculated an APE of approximately $1,070,000 for 

33 the 20-year license renewal period (Exelon 2013b).

34 Averted Offsite Property Damage Costs

35 The averted offsite property damage costs (AOC) were calculated using the following formula:

36 AOC = Annual CDF reduction

37 × offsite economic costs associated with a severe accident (on a per-event 

38 basis) 

39 × present value conversion factor

40 This term represents the sum of the frequency-weighted offsite economic costs for each release 

41 category, as obtained for the Level 3 risk analysis. For the purposes of initial screening, which 

42 assumes elimination of all severe accidents caused by internal events, Exelon calculated an 
Appendix F

F-38

1 OECR of about $254,600 based on the Level 3 risk analysis (Exelon 2013b). This results in a 

2 discounted value, or AOC, of approximately $3,830,000 for the 20-year license renewal period.

3 Averted Occupational Exposure Costs

4 The averted occupational exposure (AOE) costs were calculated using the following formula:

5 AOE = Annual CDF reduction

6 × occupational exposure per core damage event

7 × monetary equivalent of unit dose

8 × present value conversion factor

9 Exelon derived the values for AOE from information provided in Section 5.7.3 of the regulatory 

10 analysis handbook (NRC 1997c). Best estimate values provided for immediate occupational 

11 dose (3,300 person-rem) and long-term occupational dose (20,000 person-rem over a 10-year 

12 cleanup period) were used. The present value of these doses was calculated using the 

13 equations provided in the handbook in conjunction with a monetary equivalent of unit dose of 

14 $2,000 per person-rem, a real discount rate of 3 percent, and a time period of 20 years to 

15 represent the license renewal period. For the purposes of initial screening, which assumes 

16 elimination of all severe accidents caused by internal events, Exelon calculated an AOE of 

17 approximately $24,600 for the 20-year license renewal period (Exelon 2013b).

18 Averted Onsite Costs

19 Averted onsite costs (AOSC) include averted cleanup and decontamination costs (ACC) and 

20 averted power replacement costs. Repair and refurbishment costs are considered for 

21 recoverable accidents only and not for severe accidents. Exelon derived the values for AOSC 

22 based on information provided in Section 5.7.6 of NUREG/BR–0184, the regulatory analysis 

23 handbook (NRC 1997c).

24 Exelon divided this cost element into two parts—the onsite cleanup and decontamination cost, 

25 also commonly referred to as ACC, and the RPC.

26 ACCs were calculated using the following formula:

27 ACC = Annual CDF reduction

28 × present value of cleanup costs per core damage event

29 × present value conversion factor

30 The total cost of cleanup and decontamination subsequent to a severe accident is estimated in 

NUREG/BR–0184 to be $1.5×109 31 (undiscounted). This value was converted to present costs 

32 over a 10-year cleanup period and integrated over the term of the proposed license extension. 

33 For the purposes of initial screening, which assumes elimination of all severe accidents caused 

34 by internal events, Exelon calculated an ACC of approximately $774,000 for the 20-year license 

35 renewal period.

36 Long-term RPCs were calculated using the following formula:

37 RPC = Annual CDF reduction

38 × present value of replacement power for a single event

39 × factor to account for remaining service years for which replacement power is 

40 required

41 × reactor power scaling factor
Appendix F

F-39

1 Exelon based its calculations on a Byron net output of 1,185 megawatts electric (MWe) and 

2 scaled up from the 910-MWe reference plant in NUREG/BR–0184 (NRC 1997c). Therefore, 

3 Exelon applied a power scaling factor of 1185/910 to determine the RPCs. For the purposes of 

4 initial screening, which assumes elimination of all severe accidents caused by internal events, 

5 Exelon calculated an RPC of approximately $286,000 and an AOSC of approximately 

6 $1,060,000 for the 20-year license renewal period.

7 Using the above equations, Exelon estimated the total present dollar value equivalent 

8 associated with completely eliminating severe accidents from internal events at Byron to be 

9 about $5,979,393, also referred to as the maximum averted cost-risk (MACR). The internal 

10 events MACR is rounded to the next highest thousand ($5,980,000) for SAMA calculations. 

11 Use of a multiplier of 2.5 to account for external events increases the value to $14.95M and 

12 represents the dollar value associated with completely eliminating all internal and external event 

13 severe accident risk for Byron, also referred to as the modified MACR. 

14 Exelon’s Results

15 If the implementation costs for a candidate SAMA exceeded the calculated benefit, the SAMA 

16 was considered not to be cost-beneficial. In the baseline analysis contained in the ER (using a 

17 3 percent discount rate), Exelon identified 10 potentially cost-beneficial SAMAs (SAMAs 3, 5, 9, 

18 10, 13, 15, 25, 26, 27, and 31). Based on consideration of uncertainty analysis, Exelon 

19 identified an additional eight potentially cost-beneficial SAMAs (SAMAs 2, 7, 8, 11, 16, 19, 28, 

20 and 30). In response to NRC staff RAI, Exelon provided the results of revised baseline and 

21 uncertainty analyses to account for updated SAMA implementation cost estimates, a revised 

22 multiplier of 2.6 to account for external events, and revisions to the uncertainty analysis

23 (Exelon 2014). As a result, Exelon did not identify any additional cost-beneficial SAMAs in the 

24 baseline analysis, but did identify two additional potentially cost-beneficial SAMAs when 

25 uncertainties were considered (SAMAs 1 and 4). 

26 The potentially cost-beneficial SAMAs for Byron are as follows:

27 • SAMA 1 – Install Diesel-Driven SX Pump in a new dedicated building

28 • SAMA 2 – Replace the Positive Displacement Pump with a Self-Cooled, 

29 Auto-Start Pump

30 • SAMA 3 – Auto Start of Standby SX Pump

31 • SAMA 4 – Install “No Leak” Seals

32 • SAMA 5 – Modify the Startup Feedwater Pump to Start Using the AMSAC SG 

33 Low-Low-Low Level Signal to Mitigate AFW Failure 

34 • SAMA 7 – Establish Flow to the RHR HX on RHR Pump Start

35 • SAMA 8 – Install Kill Switches for the Fire Protection Pumps in the MCR

36 • SAMA 9 – Install Flow Restrictors in Fire Protection Pipes

37 • SAMA 10 – Alter Ductwork Between the Aux BLDG Room and the SX Pump 

38 Room

39 • SAMA 11 – Implement DMS

40 • SAMA 13 – Alternate AFW Cooling with Seal Protection

41 • SAMA 15 – Resolve Regulatory Issues and Complete Implementation of the 

42 Interunit AFW Crosstie
Appendix F

F-40

1 • SAMA 16 – Install High-Flow Sensors on the non-Essential Service Water 

2 System

3 • SAMA 19 – Replace MOVs in the RHR Discharge Line with Valves that can 

4 Isolate an ISLOCA Event

5 • SAMA 25 – Install a Filtered Containment Vent

6 • SAMA 26 – DMS Using a Dedicated Generator, Self-Cooled charging Pump, 

7 and a Portable AFW Pump

8 • SAMA 27 – Protect RHR, SI and CVCS Cubicle Cooling Fan Cables in Fire 

9 Zone 11.3-0 

10 • SAMA 28 – Install Fire Barriers Around MCC 134X

11 • SAMA 30 – Protect AFW Cables in the AUX Building General Area, 

12 Elevation 383′

13 • SAMA 31 – Protect Cables for 2AF013A, B, and D in the AUX Building 

14 General Area, Elevation 426′

15 The potentially cost-beneficial SAMAs and Exelon’s plans for further evaluation of these SAMAs 

16 are discussed in more detail in Section F.6.2.

17 F.6.2 Review of Exelon’s Cost-Benefit Evaluation 

18 The cost-benefit analysis performed by Exelon was based primarily on NUREG/BR–0184 

19 (NRC 1997c) and discount rate guidelines in NUREG/BR–0058 (NRC 2004) and was executed 

20 consistent with this guidance. 

21 SAMAs identified primarily on the basis of the internal events analysis could provide benefits in 

22 certain external events, in addition to their benefits in internal events. Exelon accounted for the 

23 potential risk reduction benefits associated with external events by applying a multiplier to the 

24 estimated benefits for internal events. In the analysis reported in the ER, Exelon multiplied the 

25 estimated benefits for internal events by a factor of 2.5 incorporating an external events 

26 multiplier of 1.5 to account for external events (Exelon 2013b). As discussed above, 10 SAMAs 

27 were determined to be potentially cost-beneficial in Exelon’s baseline analysis (SAMAs 3, 5, 9, 

28 10, 13, 15, 25, 26, 27, and 31). As discussed in Section F.2.2.2, in response to an NRC staff 

29 RAI, Exelon provided a revised baseline evaluation by applying a multiplier of 2.6 [(fire CDF of 

5.39×10−5 per year + seismic CDF of 1.0×10−6 per year + external flooding CDF of 1.0×10−6 30 per 

year + high winds CDF of 1.0×10−6 31 per year + transportation and nearby facility accident CDF of 

1.0×10−6 per year) / (internal events CDF of 3.97×10−5 32 per year) + 1] to account for external 

33 events (Exelon 2014). The results of this revised evaluation are provided in Table F–5. No 

34 additional potentially cost-beneficial SAMAs were identified as a result of this revised evaluation

35 (using a multiplier of 2.6 and a 3-percent discount rate), which incorporated the revised SAMA

36 implementation costs discussed in Section F.5. 

37 Exelon considered the impact that possible increases in benefits from analysis uncertainties 

38 would have on the results of the SAMA assessment. In the ER, Exelon presents the results of 

39 an uncertainty analysis of the internal events CDF which indicates that the 95th-percentile value 

40 is a factor of 2.49 times the point estimate CDF for Byron. Exelon considered whether any 

41 additional Phase I SAMAs might be retained for further analysis if the benefits from internal and 

42 external events were increased by a factor of 2.49. One additional SAMA (SAMA 20) was 

43 identified. Exelon also considered the impact on the Phase II screening if the estimated benefits 

44 from internal and external events were increased by a factor of 2.49. The additional Phase I 
Appendix F

F-41

1 SAMA, SAMA 20, was included in this sensitivity analysis. As discussed above, eight SAMAs 

2 (SAMAs 2, 7, 8, 11, 16, 19, 28, and 30) were determined to be potentially cost-beneficial in 

3 Exelon’s analysis. 

4 In an RAI, the NRC staff noted that the mean CDF (for PRA model BB011a) was lower than the 

5 point estimate and that, usually, the mean CDF is greater than the point estimate because of the 

6 correlation of uncertainties (NRC 2014). In response to the RAI, Exelon responded that many of 

7 the largest contributors to the Byron PRA results are human probabilities, joint human error 

8 probabilities (JHEPs), or flood mitigation events that include operator errors, which are not 

9 correlated events. In addition, several contributors with large failure probabilities were assigned 

10 lognormal distributions with relatively high error factors. These factors can act to reduce the 

11 mean relative to the point estimate. Exelon redid the uncertainty analysis using revised error 

12 factors for selected events and determined that the revised 95th-percentile value is a factor of 

13 2.53 times the point estimate CDF for Byron. Exelon considered whether any additional Phase I 

14 SAMAs might be retained for further analysis if the benefits from internal and external events 

15 were increased by a factor of 2.53 (in addition to the multiplier of 2.6 for external events and 

16 revised SAMA implementation costs discussed in Section F.5). One additional SAMA (SAMA 1) 

17 was identified. Exelon also considered the impact on the Phase II screening if the estimated 

18 benefits from internal and external events were increased by a factor of 2.53 (in addition to the 

19 multiplier of 2.6 for external events and revised SAMA implementation costs discussed in 

20 Section F.5). Two additional SAMAs (SAMAs 1 and 4) became cost-beneficial as a result of this 

21 revised evaluation (using a 3-percent discount rate) (Exelon 2014). The results of this revised 

22 evaluation are provided in Table F–5.

23 Exelon provided the results of additional sensitivity analyses in the ER, including the use of a 

24 7-percent discount rate and variations in MACCS2 input parameters (as discussed in 

25 Section F.2.2.4). Exelon determined that these analyses did not identify any additional 

26 potentially cost-beneficial SAMAs (Exelon 2013b). In an RAI, the NRC staff requested that 

27 Exelon to explain why the MACCS2 sensitivity case for economic rate of return resulted in a 

28 change in dose consequence (NRC 2014). In response to the RAI, Exelon provided clarification 

29 that the rate of return on property impacts the estimated property that is condemned (or 

30 reclaimed). Changes in property reclamation will result in changes in dose consequences to 

31 those who occupy the property after it has been reclaimed (Exelon 2014). The NRC staff 

32 considers this explanation reasonable.

33 Exelon stated in the ER (Exelon 2013a) that SAMA 15, Resolve Regulatory Issues and 

34 Complete Implementation of the Interunit AFW Crosstie, to improve AFW reliability, was in the 

35 final stages of implementation at Byron at the time of the ER submittal and was therefore 

36 included as a SAMA rather than being included in the base PRA model. A sensitivity analysis 

37 was provided in the ER in which SAMA 15 was incorporated into the base PRA model and the 

38 Phase I and II SAMAs reevaluated. This reevaluation did not alter the conclusions of either the 

39 Phase I screening analysis or the Phase II cost-benefit analysis.

40 Exelon also stated in the ER that many of the SAMAs address similar areas of plant risk and 

41 that implementation of one SAMA may result in other SAMAs no longer being cost-beneficial. 

42 Exelon further noted that SAMA 11, Implement DMS, would mitigate many of the largest 

43 contributors to Byron risk, and that it may be fully or partially implemented at Byron for reasons 

44 other than the results of the SAMA analysis (specifically, it includes capabilities to address 

45 insights from the Fukushima Dai-ichi accident). Exelon reevaluated the cost-beneficial SAMAs 

46 assuming both SAMA 15 and SAMA 11 are implemented in an attempt to optimize a reduced 

47 set of SAMAs that would address the largest risk contributors. As a result, 10 SAMAs were 

48 determined to no longer be cost-beneficial (SAMAs 2, 3, 8, 9, 10, 13, 16, 25, 26, and 27)

49 (Exelon 2013b). In the response to the NRC staff RAI discussed above regarding the revised 
Appendix F

F-42

1 uncertainty evaluation (applying the factor of 2.53 for uncertainty and the multiplier of 2.6 for 

2 external events), Exelon also determined that SAMA 1 would no longer be cost-beneficial if both 

3 SAMAs 11 and 15 were implemented (Exelon 2014). SAMA 4 is also effectively implemented in 

4 this analysis since installing “no leak” RCP seals is one element of SAMA 11. 

5 Exelon stated in the ER that the 18 SAMAs (SAMAs 2, 3, 5, 7, 8, 9, 10, 11, 13, 15, 16, 19, 25, 

6 26, 27, 28, 30, and 31) determined to be cost-beneficial in the ER baseline and uncertainty 

7 evaluations have been submitted to the Byron Plant Health Committee for further 

8 implementation consideration (Exelon 2013b). Exelon made no similar commitment for 

9 SAMAs 1 and 4, which were determined to be potentially cost-beneficial in response to NRC 

10 staff RAIs. In responses to NRC staff RAIs, Exelon stated that installation of SAMA 4 at Byron 

11 is planned, that contract awards have been made to install the new RCP seals, and that 

12 engineering and analysis work necessary to install the new seals has begun (Exelon 2014). As 

13 discussed previously, Exelon stated in the ER that SAMA 11 may be fully or partially 

14 implemented at Byron for other purposes, which, if fully implemented along with SAMA 15 

15 (which is currently being implemented), would result in SAMA 1’s no longer being cost16 beneficial. 

17 Given that Exelon’s cost benefit evaluations have been reviewed by the NRC staff and that 

18 Exelon has satisfactorily addressed NRC staff questions regarding the evaluations, the NRC 

19 staff concludes that the cost-benefit evaluations are of sufficient quality to support the SAMA

20 evaluation. Therefore, the NRC staff concludes that, with the exception of the potentially 

21 cost-beneficial SAMAs discussed above, the costs of the other SAMAs evaluated would be 

22 higher than their associated benefits.

23 F.7 Conclusions

24 Exelon initially compiled a list of 30 SAMAs based on a review of the most significant basic 

25 events from the plant-specific PRA and insights from the Byron PRA group, insights from the 

26 plant-specific IPE and IPEEE, and Phase II SAMAs from license renewal applications for other 

27 plants. An initial qualitative screening removed SAMA candidates that: (1) are not applicable to

28 Byron design due to design differences, (2) have already been implemented at Byron or the 

29 intent achieved by other means, or (3) have excessive implementation costs. Based on this 

30 initial screening, 3 SAMAs were eliminated leaving 27 candidate SAMAs for evaluation. 

31 One additional candidate SAMA was also further evaluated after accounting for analysis 

32 uncertainties. 

33 For the remaining 28 SAMA candidates, benefit and cost estimates were developed as shown in 

34 Table F–5. The cost-benefit analyses in the ER showed that 10 of the SAMA candidates were 

35 potentially cost-beneficial in the baseline analysis (SAMAs 3, 5, 9, 10, 13, 15, 25, 26, 27, and 

36 31). Exelon performed additional analyses to evaluate the impact of parameter choices and 

37 uncertainties on the results of the SAMA assessment. As a result, eight additional SAMAs were 

38 identified as potentially cost-beneficial (SAMAs 2, 7, 8, 11, 16, 19, 28, and 30). Exelon has 

39 indicated that all 18 potentially cost-beneficial SAMAs will be submitted to the Byron Plant 

40 Health Committee for further implementation consideration.

41 In response to NRC staff RAI, Exelon reevaluated the 28 SAMA candidates and 1 additional 

42 SAMA candidate and, as a result, identified 2 additional potentially cost-beneficial SAMAs 

43 (SAMAs 1 and 4). Exelon has plans to implement SAMA 4 and has initiated engineering and 

44 procurement activities to do so. Since full implementation of SAMA 11 in conjunction with 

45 SAMA 15 (which is currently being implemented) would result in SAMA 1 not being 

46 cost-beneficial, the NRC staff concludes that the applicant should consider SAMA 1 for further 

47 evaluation, depending on the degree of implementation of SAMA 11. 
Appendix F

F-43

1 The NRC staff reviewed the Exelon analysis and concludes that the methods used and the 

2 implementation of those methods are sound. The treatment of SAMA benefits and costs 

3 support the general conclusion that the SAMA evaluations performed by Exelon are reasonable 

4 and sufficient for the license renewal submittal. Although the treatment of SAMAs for external 

5 events was somewhat limited, the NRC staff determined that the likelihood of there being 

6 additional cost-beneficial enhancements in this area was minimized by utilizing an interim Byron 

7 fire PRA to identify SAMA candidates, resolution of suggested plant improvements that were 

8 identified as a result of the IPEEE process, and inclusion of a multiplier to account for the 

9 external events.

10 Based on the NRC staff’s review of Exelon’s SAMA evaluations, including Exelon’s response to 

11 NRC staff questions regarding the evaluations, the NRC staff concludes that Exelon has 

12 adequately identified areas in which risk can be further reduced in a cost-beneficial manner 

13 through the implementation of the identified potentially cost-beneficial SAMAs. Given the 

14 potential for cost-beneficial risk reduction, the NRC staff concludes that further Exelon 

15 evaluation of the candidate SAMAs identified as being potentially cost-beneficial in the Exelon 

16 ER is appropriate. 

17 Additionally, the NRC staff evaluated the identified potentially cost-beneficial SAMAs to 

18 determine if they are in the scope of license renewal, i.e., they are subject to aging 

19 management. This evaluation considers whether the structures, systems, and components 

20 (SSCs) associated with these SAMAs: (1) perform their intended function without moving parts 

21 or without a change in configuration or properties and (2) that these SSCs are not subject to 

22 replacement based on qualified life or specified time period. The NRC staff determined that 

23 these SAMAs do not relate to adequately managing the effects of aging during the period of 

24 extended operation. Therefore, they need not be implemented as part of license renewal in 

25 accordance with Title 10 of the Code of Federal Regulations, Part 54, “Requirements for 

26 renewal of operating licenses for nuclear power plants.”

27 F.8 References

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Appendix F

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32 No. ML061510619.[PECO] Philadelphia Electric Company. 1989. Limerick Generating Station, 

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45 Mitigation Design Alternatives. June 23, 1989.
Appendix F

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Appendix F

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39 Revision 0. WCAP-16341-P. November 2005.






UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

------------------

OFFICIAL BUSINESS
NUREG-1437

Supplement 54

Draft

Generic Environmental Impact Statement for License Renewal of Nuclear Plants 

Regarding Byron Station, Units 1 and 2